Chapter 10: Steam and Power Conversion System Table of

Revision 43—09/27/07 NAPS UFSAR 10-i

Chapter 10: Steam and Power Conversion System

Table of Contents

Section Title Page

10.1 SUMMARY DESCRIPTION . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.1-1

10.2 TURBINE GENERATOR . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-110.2.1 Turbine Missiles. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-610.2.1.1 Probability of Generation and Ejection (P1) . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-610.2.1.2 Probability of Missile Strike (P2). . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-710.2.1.3 Probability of Damage (P3) . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-1010.2.1.4 Assumptions Used for North Anna Turbine Evaluations. . . . . . . . . . . . . . . . 10.2-1210.2.1.5 Targets Eliminated Based on Redundancy. . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-1210.2.1.6 Intermediate Barriers . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-1310.2.1.7 Overall Probability Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-1410.2.1.8 Conclusion . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-14

10.2 References. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-1510.2 Reference Drawings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-16

10.3 MAIN STEAM SYSTEM . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-110.3.1 Design Basis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-110.3.2 System Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-110.3.3 Performance Analysis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-610.3.3.1 Potential for Unisolable Blowdown of All Three Steam Generators . . . . . . . 10.3-710.3.3.2 Tests Ensuring Steam System Valve Integrity . . . . . . . . . . . . . . . . . . . . . . . . 10.3-710.3.4 Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-810.3 Reference Drawings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-8

10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM. . 10.4-110.4.1 Auxiliary Steam System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-110.4.1.1 Design Basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-110.4.1.2 System Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-110.4.1.3 Performance Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-210.4.1.4 Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-210.4.1.5 Instrumentation Application. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-210.4.2 Circulating Water System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-310.4.2.1 Design Basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-310.4.2.2 System Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-310.4.2.3 Performance Analysis. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-410.4.2.4 Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-6

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Chapter 10: Steam and Power Conversion SystemTable of Contents (continued)

Section Title Page

10.4.2.5 Instrumentation Application. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-610.4.3 Condensate and Feedwater Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-710.4.3.1 Design Basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-710.4.3.2 System Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-710.4.3.3 Design Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1110.4.3.4 Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1610.4.3.5 Instrumentation Application. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1710.4.4 Main Condenser . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1710.4.4.1 Design Basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1710.4.4.2 System Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1810.4.4.3 Design Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1910.4.4.4 Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1910.4.4.5 Instrumentation Application. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1910.4.5 Lubricating Oil System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1910.4.5.1 Design Basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1910.4.5.2 System Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-1910.4.5.3 Design Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2010.4.5.4 Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2010.4.5.5 Instrumentation Application. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2010.4.6 Secondary Vent and Drain Systems. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2110.4.6.1 Design Basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2110.4.6.2 System Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2110.4.6.3 Design Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2310.4.6.4 Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2410.4.6.5 Instrumentation Application. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2410.4.7 Bearing Cooling Water System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2410.4.7.1 Design Basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2410.4.7.2 System Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2510.4.7.3 Design Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2610.4.7.4 Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2710.4.7.5 Instrumentation Application. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2710.4.8 Condensate Polishing System—Powdered-Resin Type . . . . . . . . . . . . . . . . . . 10.4-2710.4.8.1 Design Basis . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2710.4.8.2 System Description. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2810.4.8.3 Safety Evaluation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-29

Revision 43—09/27/07 NAPS UFSAR 10-iii

Chapter 10: Steam and Power Conversion SystemTable of Contents (continued)

Section Title Page

10.4.8.4 Tests and Inspections . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2910.4.8.5 Instrumentation Application. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-2910.4 Reference Drawings . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-30

Revision 43—09/27/07 NAPS UFSAR 10-iv

Table 10.2-1 Failure Analysis of Gland Steam Seal System Components . . . . . . . . . . . 10.2-17Table 10.2-2 Total Damage Probability for 1 Year of Continuous Operation Using

Criterion A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-19Table 10.2-3 Total Damage Probability for 1 Year of Continuous Operation Using

Criterion B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-20Table 10.2-4 Total Damage Probability for 2 Years of Continuous Operation Using

Criterion A . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-21Table 10.2-5 Total Damage Probability for 2 Years of Continuous Operation Using

Criterion B . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-22Table 10.2-6 Total Probability for Each Unit-Trajectory Case . . . . . . . . . . . . . . . . . . . . 10.2-23Table 10.2-7 Turbine Target Distances and Impact Areas - Unit 1 Turbine . . . . . . . . . . 10.2-24Table 10.2-8 Turbine Target Distances and Impact Areas - Unit 2 Turbine . . . . . . . . . . 10.2-26Table 10.3-1 Tests Ensuring Steam System Integrity Main Steam Trip Valves . . . . . . . 10.3-9Table 10.3-2 Tests Ensuring Steam System Integrity Main Steam Nonreturn Valves . . 10.3-10Table 10.3-3 Tests Ensuring Steam System Integrity Steam Dump Valves . . . . . . . . . . 10.3-11Table 10.3-4 Tests Ensuring Steam System Integrity Turbine Throttle and

Governor Valves . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-12Table 10.4-1 Auxiliary Feedwater System Design Basis. . . . . . . . . . . . . . . . . . . . . . . . . 10.4-32Table 10.4-2 Design Data for Major Components of Condensate and

Feedwater Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-33Table 10.4-3 Criteria for Auxiliary Feedwater System Design-Basis Conditions . . . . . . 10.4-39Table 10.4-4 Summary of Assumptions Used in Auxiliary Feedwater System

Design Verification Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-40Table 10.4-5 Failure Analysis of Auxiliary Feedwater Components. . . . . . . . . . . . . . . . 10.4-43Table 10.4-6 Design Data for Major Components of the Bearing Cooling

Water System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-45


List of Tables

Table Title Page

Revision 43—09/27/07 NAPS UFSAR 10-v


List of Figures

Figure Title Page

Figure 10.1-1 Unit 1 Heat Balance Diagram - 2905 MWt Load. . . . . . . . . . . . . . . . . . . 10.1-4Figure 10.1-2 Unit 2 Heat Balance Diagram - 2905 MWt Load. . . . . . . . . . . . . . . . . . . 10.1-5Figure 10.2-1 Total Low Trajectory Turbine Missile Envelope . . . . . . . . . . . . . . . . . . . 10.2-28Figure 10.2-2 Turbine Missiles . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-29Figure 10.2-3 Turbine Missile Reference System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-30Figure 10.2-4 Top View of Idealized Target. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-31Figure 10.2-5 Side View of Idealized Target . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.2-32Figure 10.3-1 Main Steam System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-14Figure 10.3-2 Main Steam Line Trip Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-16Figure 10.3-3 Main Steam Line Non-Return Valve . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.3-17Figure 10.4-1 Circulating Water System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-46Figure 10.4-2 Turbine Building Flooding After Circulating Water Expansion

Joint Rupture . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-47Figure 10.4-3 Condensate System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-48Figure 10.4-4 Feedwater System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-52Figure 10.4-5 Chemical Feed System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-53Figure 10.4-6 Auxiliary Feedwater System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-54Figure 10.4-7 Lubricating Oil System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-55Figure 10.4-8 Steam Generator Blowdown System . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-56Figure 10.4-9 Bearing Cooling System. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 10.4-57

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Intentionally Blank

Revision 43—09/27/07 NAPS UFSAR 10.1-1

Chapter 10STEAM AND POWER CONVERSION SYSTEM

10.1 SUMMARY DESCRIPTION

Note: As required by the Renewed Operating Licenses for North Anna Units 1 and 2, issuedMarch 20, 2003, various systems, structures, and components discussed within this chapter aresubject to aging management. The programs and activities necessary to manage the aging of thesesystems, structures, and components are discussed in Chapter 18.

This section describes that category of systems and equipment that are required to convertsteam energy to electrical energy. The following sections describe separate equipment andsystems required for each unit:

10.2 Turbine Generator

10.3 Main Steam System

10.4.1 Auxiliary Steam System

10.4.2 Circulating Water System

10.4.3 Condensate and Feedwater System

10.4.4 Main Condenser

10.4.5 Lubricating Oil System

10.4.6 Secondary Vent and Drain Systems

10.4.7 Bearing Cooling Water System

10.4.8 Condensate Polishing System

The following system design features are safety related:

1. Main steam lines from the steam generators up to and including the main steam linenonreturn valves (Section 10.3).

2. Feedwater lines from the steam generators up to and including the isolation valves outsidethe containment (Section 10.4.3).

3. All components of the auxiliary feedwater system (Section 10.4.3).

4. Screen wash pump and discharge piping providing makeup to the Service Water Reservoir(Section 10.4.2).

5. Steam generator blowdown lines from the steam generators up to and including the isolationvalves outside the containment (Section 10.4.6).


6. That portion of main air ejector discharge piping from the check valve inside containment,and penetrating the reactor containment outward to the second isolation valve outside thecontainment.

The design bases of the steam and power conversion equipment and systems are largelyderived from past design experience with fossil-fueled stations and have evolved over a longperiod of time. Specifically, the design bases are oriented to a high degree of operationalreliability at optimal thermal performance. The performance of the collective equipment andsystems is a function of environmental conditions and the selection of design options. Allauxiliary equipment was designed for the maximum expected unit capability.

The conventional design bases have been modified in order to provide suitability for nuclearapplication. These modifications include provisions for specific earthquake, tornado, and missileprotection, as further described in other sections.

Figures 10.1-1 and 10.1-2 show the heat balance for the current core rating equivalent to2905 MWt for each unit.

These heat balances show the overall steam and power conversion system and indicate theperformance requirements of the major equipment. More detailed system diagrams and designdata are presented in succeeding sections.

The steam generated by the nuclear steam supply system (NSSS) is distributed to theturbine generator by the main steam system. The turbine is an 1800-rpm tandem-compound,four-flow machine coupled to a hydrogen-cooled generator. Four combination moistureseparator-reheaters are installed to remove any moisture from the steam as it passes between thehigh- and low-pressure turbines.

Six stages of feedwater heating are provided. All heaters are of the closed type and consistof two shells resulting in a two-train condensate and feedwater piping system.

The turbine exhausts to a two-shell, single-pass steam surface condenser. Three half-sizecondensate pumps are provided. During normal operation, two of these pumps pump thecondensate through the air ejector condensers, gland steam condenser, flash evaporator, fifth-pointdrain coolers, and the sixth-, fifth-, fourth-, third-, and second-point feedwater heaters to thesuction side of the steam generator feed pumps.

Three half-size steam generator feed pumps are provided. During normal operation, two ofthese pumps pump the condensate through the first-point heater and the feedwater regulatingvalves to the steam generators. Drains from the reheaters drain to the first-point heater shells. Thefirst-point heater shells drain to the second-point heater. Drains from the second-point heatershells are collected in individual high-pressure heater drain receivers. Drains from the moistureseparators are collected in another high-pressure heater drain receiver. Three full-size,high-pressure heater drain pumps pump the condensate from these high-pressure heater drain


receivers to the suction side of the steam generator feed pumps. Drains from the third-point heatershells drain to the fourth-point heater. Two full-size, low-pressure heater drain pumps pumpfourth-point heater drains to the condensate stream between the third- and fourth-point heaters.The drains from the fifth-point heater cascade to an external fifth-point heater drain cooler. Thedrains from this drain cooler and the sixth-point heater drain to the condenser.


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Intentionally Blank


10.2 TURBINE GENERATOR

The turbine is a conventional 1800-rpm, tandem-compound unit (WestinghouseModel BB-281), consisting of one double-flow, high-pressure cylinder and two double-flow,low-pressure cylinders. The turbine can achieve a maximum capability of 983,917 kW gross with11,946,287 lb/hr of steam at inlet conditions of 828 psia and 0.38% moisture exhausting to2.07 in. Hg abs. The turbine is provided with four moisture separator-reheaters, located betweenthe high-pressure and low-pressure cylinders. Turbine extraction connections supply steam to sixstages of feedwater heaters.

Each high-pressure steam line to the high-pressure cylinder contains a stop-trip (throttle)valve and a governor control valve. A stop valve and an intercept valve are provided in thecrossover piping between each moisture separator and the low-pressure turbine cylinders.

The nuclear steam supply system is designed to follow turbine load changes not exceeding a10% step or 5%/minute ramp without a reactor trip.

A gland steam sealing system is provided to prevent air inleakage and steam outleakagealong the turbine shaft. The turbine gland steam system consists of a main supply valve thatreduces high-pressure steam to 140 psia and supplies gland supply valves that maintain 16 psia atthe turbine shaft glands. A high-pressure spillover valve is designed to limit pressure buildup to21 psia in the gland supply lines to the high-pressure turbine. Higher pressures can be acceptedprovided that the gland sealing function, i.e. no steam leakage from the glands, is maintained. Allnecessary piping and controls and a gland steam condenser are provided. Steam condensed in thegland steam condenser is drained to the main condenser. Noncondensibles are removed by anexhauster on the condenser and are discharged to the atmosphere. The radiological evaluation ofthese releases is discussed in Chapter 11. A failure analysis of the gland steam sealing system isprovided in Table 10.2-1.

The turbine control system is of the electrohydraulic type, ensuring rapid speed of responseand close control of turbine operation. The control system includes an overspeed protectioncontroller, which acts to hold unit speed in case of a load rejection. The controller operates toattempt to prevent a turbine overspeed trip by closing the turbine governor valves and the reheatintercept valves until the overspeed condition is corrected.

The valves are then automatically reopened. The protective devices for the turbine include alow bearing oil pressure trip, a solenoid trip, overspeed trips, a thrust bearing trip, and a lowvacuum trip. Solenoid trip will be actuated on malfunctions of the steam and power conversionsystem, such as reactor trip, generator trip, AMSAC initiation, loss of feedwater flow, and loss ofelectrohydraulic governor power. A solenoid trip can also be actuated manually from the maincontrol room. Nonreturn valves are installed in the turbine extraction steam lines, as required, tominimize turbine overspeed following a trip.


The turbine trip signals are sensed locally at the turbine via three pressure switches in theturbine auto-stop oil system and via limit switches on the four turbine stop valves. The pressureswitches send trip signals via channels as do the limit switches on the turbine stop valves to theWestinghouse solid-state logic protection system (see Section 7.2). Should two out of threepressure switches or four out of four limit switches indicate a turbine trip condition, signals willbe sent via channels to the redundant Westinghouse cabinets. Two-position, key-lock switches(“normal-trip”) installed locally at the turbine such that if a failure of a pressure switch or limitswitch occurred the appropriate channel would be placed in the “trip” position. This is incompliance with the requirements of the Technical Specifications.

Motoring occurs when the steam supply to the turbine is shut off while the generator is stillon line. Because there is insufficient steam energy available to overcome the turbine generatorlosses, the generator will act as a synchronous motor and drive the turbine. Although the conditionis generally described as generator motoring, the protection is not for the generator but to preventoverheating the low-pressure turbine of high-pressure turbine blading. This protection consists ofone reverse power relay which provides anti-motoring protection for the turbine generator uponloss of the prime mover. Motoring of the generator is annunciated in the Control Room and afterforty seconds will initiate a generator and unit trip. Sequential tripping is the inclusion of a secondreverse power relay in series with any trip circuits using steam valve closed position switches,turbine trip oil pressure switches or high pressure steam differential switches. The Sequentialtripping ensures that the generator has started motoring before the main breakers are allowed toopen. A static Basler relay is installed into a separate control circuit and provides a trip input tothe following independent lockout relays: stop valve differential, 86V, turbine intercept and reheatvalve differential, 86V1, and turbine anti-motoring (timer), TD. These lockout relays will trip themain generator thirty seconds after a motoring condition begins.

The mechanical overspeed trip system will stop the flow of all steam into the turbine,should the speed increase a predetermined amount above normal. The mechanism consists of atrip weight that is carried in a transverse hole in the rotor body, with its center of gravity offsetfrom the axis of rotation, so that centrifugal force tends to move it outward at all times. The tripweight is held in position by a compression spring. If the speed of the turbine increases to a speedabove the setpoint, the centrifugal force overcomes the compression of the spring, and the weightmoves outward and strikes the trip trigger. This causes the draining of the auto-stop oil and theloss of pressure in the chamber above the diaphragm of the interface emergency trip valve. Thisopens the valve and drains the operating fluid beneath the hydraulic piston system, closing allvalves capable of admitting steam to the turbine.

After the mechanism has tripped, it must be manually reset. It is impossible to reset the tripuntil the trip weight returns to its normal position (at 2% above normal speed). This trip devicecan also be tripped manually. The mechanical trip device will function at 111% of rated turbinespeed.


The second method of tripping the turbine on overspeed using the auto-stop oil system isprovided by the primary speed channel, which receives a continuous turbine speed signal from avariable reluctance transducer mounted at the turbine shaft. The transducer output is a series ofpulses whose frequency is proportional to turbine speed. This signal is converted to a precise dcsignal with a level proportional to turbine speed. At 111% of turbine speed, this system operatesthe emergency trip solenoid valve located on the emergency trip control block. The actuation ofthe emergency trip solenoid valve will cause the auto-stop oil to drain and the opening of theinterface emergency trip valve to open, as described above, subsequently closing all valvescapable of admitting steam to the turbine.

An auxiliary speed channel provides a separate overspeed trip system, sharing none of thesame components as the above-described systems. It receives frequency pulses generated by aseparate reluctance pickup and converts them to a proportional analog signal for the control ofoverspeed. If the turbine speed exceeds 103% of normal rated speed, this system will open twosolenoid valves in the hydraulic oil system, causing the turbine governor and intercept valves toclose.

Detailed procedures for the turbine overspeed trip system tests can be found in theWestinghouse instruction book for the operation and control of the North Anna Power StationWestinghouse steam turbine. These procedures were part of the North Anna preoperational testprogram. The frequency of tests below will be increased if operating experience indicates thatmore frequent testing is advisable:

1. A thorough check of the throttle and governor valve stem freedom will be made once per184 days, except during end of cycle power coastdown between 835 MWe and 386 MWewhen testing of the governor valves may be suspended.

2. A thorough check of the reheat stop and interceptor valve stem freedom will be made onceper 18 months.

3. Motor-driven oil pumps and controls will be tested once each month. During normaloperation, this procedure involves testing the bearing oil pump pressure switch by reducingthe pressure by the use of the bleed-off valve to a point where the switch makes contact,completing the circuit to the ac pump motor. The emergency oil pump pressure switch can betested by continuing to reduce the pressure to the point where this switch makes contact, thusoperating the emergency oil pump. The actual pressure at which each switch operates iscompared to the prescribed setting.

4. The following oil trip test devices located at the governor end pedestal will be tested beforeeach turbine start-up:

a. Overspeed trip oil test device.

b. Low vacuum trip.


c. Low bearing oil pressure trip.

d. Thrust bearing oil trip.

5. The overspeed trip will be tested by overspeeding the turbine-generator unit during eachrefueling.

6. The auxiliary speed channel trip is checked during normal unit start-up.

A turbine shaft-driven main oil pump normally supplies all lubricating-oil requirements tothe turbine-generator unit. An ac motor-driven bearing oil pump is installed for supplyinglubricating oil during start-up, shutdown, and turning gear operation. An ac motor-driven bearinglift pump is also provided to supply high-pressure oil to the turbine-generator bearings beforeshaft rotation to reduce the starting load on the turning gear motor. A dc motor-driven emergencyoil pump, operated from the station battery, is also available to ensure lubricating oil to thebearings. Cooling water from the bearing cooling water system (Section 10.4.7) is used for theturbine lube-oil coolers.

A continuous bypass-type lubricating oil system (Section 10.4.5) removes water and othercontaminants from the oil. All piping and valves in the lube oil system are of welded steel, andhigh-pressure bearing oil piping is enclosed in a guard pipe.

The emergency oil pump starts on low bearing oil pressure, which may be the result of thefailure of the ac bearing oil pump to start or provide adequate oil pressure. The emergency oilpump is the only lubricating oil pump required to function, as this is the last backup to supplyadequate lubrication to allow the turbine generator to coast down to a stop after a trip. Pumpoperation will be required during a loss of ac power, and possibly during a loss-of-coolantaccident. The dc emergency oil pump is tested monthly.

To allow turning gear operation after a loss of off-site power and thereby reduce to aminimum rotor distortion on the cooling of turbine parts, the bearing oil pump, bearing lift pump,and turning gear motor are powered from the emergency bus.

The hydrogen inner-cooled generator is rated at 1,088,600 kVA at 75-psig hydrogen gaspressure, 0.90 power factor, three phase, 60 Hz, 22 kV, 1800 rpm. Generator rating, temperaturerise, and insulation class are in accordance with the latest ANSI standards, at the time ofmanufacture.

Primary protection of the main generator is provided by differential current and field failurerelays. Protective relays automatically trip the turbine stop valves and electrically isolate thegenerator.

A rotating rectifier brushless exciter with a response ratio of 0.5 is provided. The exciter israted at 4600 kW, 570V dc, 1800 rpm. The exciter consists of an ac alternator coupled directly tothe generator rotor. The alternator field winding is stationary, and control of the exciter is appliedto this winding. The alternator armature output is rectified by banks of diodes that rotate with the


armature. This dc output is carried through a hollow section of the shaft and is applied directly tothe main generator field.

The 22-kV generator terminals are connected to the main step-up transformer and the unitstation service transformers by means of 22-kV aluminum conductor enclosed in anisolated-phase bus duct. This bus duct is rated 30,500A, cooled by forced air.

Hydrogen-side and air-side ac, motor-driven, seal oil pumps are furnished to provide seal oilfor the prevention of hydrogen leakage from the generator. A dc air-side seal oil backup pump,powered from the station battery, is also provided. Backup is also provided from theturbine-generator lubricating oil system from a variety of sources. Backup is normally providedby the main oil pump. During periods of start-up, shutdown, or turning gear operation, backup isprovided by an ac motor-driven seal oil backup pump or the bearing oil pump. During aloss-of-station-power incident, seal oil is provided by the dc air-side seal oil backup pump, andbackup is provided by the dc emergency oil pump.

A malfunction of the main generator hydrogen system will not result in an explosion. Sincea mixture of hydrogen and air is explosive over a wide range of proportions (from about 4% to70% hydrogen by volume), the design of the generator and the specified operating procedures aresuch that explosive mixtures are not possible under normal operating conditions. To provide forsome unforeseen condition brought about by the failure to follow the correct operating procedure,it has been deemed necessary to design the frame to be explosion-safe. The intensity of anexplosion of a mixture of air and hydrogen varies with the proportion of the two gases present. Acurve on which the values of intensity are plotted against the proportions of gases willapproximate a sine wave, having zero values at 5% and 70% hydrogen and reaching a maximumintensity at a point halfway between these limits. The term “explosion-safe” referred to earlier isintended to mean that the frame will withstand an explosion of this most explosive proportion ofhydrogen and air at a nominal gas pressure of 2 or 3 psig without damage to life or propertyexternal to the machine. This nominal pressure of 2 or 3 psig is that which might be obtained ifhydrogen were accidentally admitted during the purging operation instead of carbon dioxide, asspecified. Such an explosion might, however, result in damage or dislocation of internal parts ofthe generator.

When changing from one gas to another, the generator is vented to the atmosphere so that apositive pressure of more than 2 or 3 psig will not be built up. It is necessary in fixing the designfeatures and operating procedure of hydrogen-cooled turbine generators to follow conservativeand safe practices. The four principal requirements of the hydrogen gas control and alarm systemare determined by the “running,” “standstill,” “gas filling,” and “gas scavenging” conditions. Infilling or scavenging the generator housing with gas, it is necessary to use an inert gas such ascarbon dioxide to make the displacement so that there will not be any mixing of hydrogen and air.It is, of course, the oxygen in the air that represents the potential hazard in conjunction withhydrogen. The primary functions of the hydrogen gas control and alarm system equipment are toprovide for scavenging and filling the generator housing with gas, to maintain the gas in the


generator housing within predetermined limits of purity, pressure, and temperature, to maintainthe gas in a moisture-free condition, and to give warning of improper operation of the generator orfailure of the gas control and alarm system.

10.2.1 Turbine Missiles

Postulated turbine missiles have been evaluated by considering the probabilities of missilegeneration and of impact to safety-related items.

The probability (P4) of damage to plant structures, systems, and components important tosafety is:

P4 = P1 × P2 × P3 (10.2-1)

where:

P1 = the probability of generation and ejection of a high-energy missile

P2 = the probability that a missile strikes a critical plant region, given its generation andejection

P3 = the probability that the missile strike damages its target in a manner leading tounacceptable consequences. Unacceptable consequences are defined here as the lossof the capacity to shut down the plant, maintain it in a safe-shutdown condition,and/or limit offsite radiation exposures.

10.2.1.1 Probability of Generation and Ejection (P1)

A turbine missile can be caused by brittle fracture of a rotating turbine part at or nearturbine operating speed, or by ductile fracture upon runaway after extensive, highly improbable,control system failures. The calculation of this probability (P1) is the responsibility ofWestinghouse. Turbine operating speed and two overspeed conditions, 120% and 190% of ratedspeed, have been used by Westinghouse in the calculation of this probability (P1). The resultingmissile generation probabilities are provided in References 1, 2, and 3.

Additional information on P1 is provided in References 4, 5, and 6.

10.2.1.1.1 Effect of Extending Reheat Stop and Intercept Valve Test Interval

Westinghouse performed an evaluation of the effects of extending the test interval of thereheat stop and intercept valves to 18 months at North Anna Power Station (Reference 12) usingfault free models and methodology from the Westinghouse report WCAP-11525 (Reference 13).The NRC staff accepted the methodology of WCAP-11525 for use in determining the probabilityof turbine missile generation in a supplemental safety evaluation issued under a cover letter datedNovember 2, 1989.


The Westinghouse evaluation (Reference 12) was performed to determine the turbinemissile ejection probability resulting from an extension of reheat stop and intercept valve testintervals. Based upon the results of the evaluation, it was determined that the total turbine missilegeneration probability meets applicable acceptance criteria with an 18-month reheat stop andintercept valve test interval.

10.2.1.1.2 Effect of Extending Main Turbine Throttle and Governor Valve Test Interval

Westinghouse performed an evaluation of the effects of extending the test interval of theturbine throttle and governor valves to 6 months at North Anna Power Station (Reference 15)using fault free models and methodology from the Westinghouse report WCAP-11525(Reference 13). The NRC staff accepted the methodology of WCAP-11525 for use in determiningthe probability of turbine missile generation in a supplemental safety evaluation issued under acover letter dated November 2, 1989.

The Westinghouse evaluation (Reference 15) was performed to determine the turbinemissile ejection probability resulting from an extension of turbine throttle and governor valve testintervals. This is consistent with the approach used in WCAP-14732 (Reference 14). Based uponthe results of the evaluation, it was determined that the total turbine missile generation probabilitymeets applicable acceptance criteria with a semi-annual turbine throttle and governor valve testinterval.

10.2.1.2 Probability of Missile Strike (P2)

In the event of missile ejection, the probability of a strike on a plant region (P2) is a functionof the energy and direction of an ejected missile and of the orientation of the turbine with respectto the plant region. The orientation of the turbine is shown on the plot plan, Reference Drawing 1.The energy, physical properties, and range of ejection angles associated with each postulatedmissile are provided by Westinghouse (References 7 & 8).

The selection of plant regions as targets was limited to those areas containing systemsessential to shut down the plant, maintain it in a safe-shutdown condition, and/or limit offsiteradiation exposures. The set of selected targets was further reduced to exclude those protected byredundancy (see Section 10.2.1.5). Those target areas included in the probability calculation arelisted below and further defined in Figures 10.2-1 and 10.2-2:

1. Reactor containment.

2. Main steam valve area.

3. Control room.

4. Relay room.

5. Auxiliary building.

6. Fuel building (portions only).


7. Cable vault.

8. Cable tunnel.

9. Fuel-oil pump house and tanks.

10. Decay tanks - waste gas.

11. Condensate storage tank.

12. Auxiliary feedwater pipe tunnel.

The probability of striking a particular region is calculated by using a solid-angle approachas follows. The turbine spins about the z-axis of the reference system shown in Figure 10.2-3. Apostulated missile is thrown from the turbine with initial velocity Vo as shown. The variableangles required to describe the resulting motion are displayed in Figure 10.2-3. Deflection anglesδ1 and δ2, provided by Westinghouse, limit θ to the range:

The probability that a single disk fragment strikes a critical area Ao is defined as:

P(Ao) = (10.2-2)

where:

Ωo = the solid angle that must be subtended by the initial velocity vector for a missile to

strike Ao

dΩ = the differential solid angle, and

f(Ω) = the probability density function

From Figure 10.2-3,

(10.2.3)

π2--- δ1– θ π

2--- δ2+≤ ≤

f Ω( ) d ΩΩo

∫

dΩ φcos φd ψd=


Given Vo, the elevation angle necessary to hit any point on Ao (described by r, y, and ψ inFigure 10.2-3) is determined from classical trajectory theory as:

= tan-1 (10.2.4)

In Equation 10.2-4, air resistance is neglected and the ± refers to high- and low-trajectorymissiles, respectively.

The probability density function f(Ω) is determined by assuming:

f(Ω) = constant = fo for 0 ≤ β ≤ 2π and π/2 - δ1 ≤ θ ≤ π/2 + δ2

f(Ω) = 0, for all other θ

From probability theory it is required that:

Therefore,

fo = (10.2-5)

The probability that n disk fragments strike a critical area Ao is, then:

P2 (Ao) = Ωo ∫ d Ω (10.2.6)

A computer program has been developed to calculate the strike probability usingEquation 10.2.6. Following Bush (Reference 9), the analysis considers high- trajectory hits on thetops of critical targets and low-trajectory hits on the sides of critical targets. Figures 10.2-4and 10.2-5 represent the top and side views of an idealized target. The strike probability of thetarget is found by numerically integrating Equation 10.2-6, which gives:

P2 = (10.2-7)

for:

π/2 - δ1 ≤ θi ≤ π/2 + δ2

φ

φ1± 1- rg/v

2o⎝ ⎠

⎛ ⎞ 22 yg/v

2o⎝ ⎠

⎛ ⎞–1/2

rg/v2o⎝ ⎠

⎛ ⎞-----------------------------------------------------------------------------

f Ω( ) ΩdallΩ∫ 1=

12π δ1 δ2sin+sin( )---------------------------------------------

n2π δ1 δ2sin+sin( )---------------------------------------------

n2π δ1 δ2sin+sin( )--------------------------------------------- φicos( ) Δφi( )Δψ

i 1=

ψn

∑


and:

P2 = 0

for:

0 ≤ θi < (π/2 - δ1), (π/2 + δ2) < θi ≤ π

where

θi = cos-1(cos φi cos ψi)

nψ = number of ground angle increments taken through the target

From Figures 10.2-4 and 10.2-5,

(10.2-8)

(10.2-9)

(10.2-10)

(10.2-11)

Equation 10.2-4 is used to determine and . The low- and high-trajectory probabilities

are calculated separately and added to obtain the final probability.

10.2.1.3 Probability of Damage (P3)

The probability (P3) is a function of the energy of the missile, its angle of impact on theaffected structure, and the ability of that structure to prevent unacceptable damage to the essentialsystems it protects. The following criteria are used:

1. For unprotected systems, a strike is considered unacceptable (P3 = 1.0).

2. For systems protected by a steel-lined concrete barrier:

a. The target is modeled as a discrete area in both the horizontal and vertical plane. Thetarget size is based on the projected area of all essential systems within the cubicledetermined by estimating the fraction of the total area occupied by these systems.

b. If a missile can perforate the concrete barrier and strike the target, it is consideredunacceptable. The perforation protection of the liner is neglected to provide conservatism.

ΔΨψmax ψmin–

nΨ-----------------------------=

ψi ψmin i 1/2–( )Δψ+=

Δφi φi2

φil

–=

φi12--- φ

i1

φi2

+⎝ ⎠⎛ ⎞=

φil

φi2


c. The conservative modified National Defense Research Council (NDRC) perforationformula (Reference 10) is used.

(This portion of the analysis was completed before the publication of Reference 10 and, sincethe use of this equation is conservative, it was not revised to use the more accurate CEA-EDFformula.)

3. For systems protected by an unlined concrete barrier:

a. The entire cubicle area is modeled as a target.

b. The CEA-EDF perforation formula (Reference 10) is used to establish perforationpotential of each missile. If a missile perforates the final barrier, damage probability (P3)is considered as 1.0.

c. If a missile does not perforate but produces backface scabbing, the damage probability(P3) is considered to be some intermediate value between 0.0 and 1.0. The actualcalculation of damage potential due to scabbing is nearly impossible, especially sincethere is the possibility of numerous scabbing fragments of various energies. However,since the total kinetic energy of all scabbed material is only 1% to 2% of the strikingmissile’s energy, it is reasonable to use a value on the low end of this range.

To allow flexibility in the damage probability associated with backface scabbing, thefollowing approach was used. An analysis using the probability equation described earlier wasperformed twice using two different criteria for unacceptable missile damage due to backfacescabbing.

1. Criterion A: Uses the conservative modified National Defense Research Council (NDRC)formula for scabbing (Reference 10), and the extreme position that the initiation of scabbingconstitutes a damage potential of 1.0.

2. Criterion B: Uses the other extreme position that the damage potential of scabbing fragmentsresulting from nonperforating impacts is 0.0.

By using the results of these two extreme analyses, the total probability for any intermediatescabbing damage probability value (Ps) can be calculated.

Total Probability = Prob. B + Ps (Prob. A - Prob. B)

The probability Ps is the sum of the damage probabilities for each of the scabbingfragments. Since these fragments are not very energetic, the number of essential componentsendangered is not great, so the best-estimate total probability is likely closer to criterion B than tocriterion A.


10.2.1.4 Assumptions Used for North Anna Turbine Evaluations

1. The failure of a disk from the low-pressure hood is assumed to create three or four equalsegments with the properties defined in References 7 and 8. The probability of generatingeither 90-degree or 120-degree segments is assumed to be equal.

2. The only targets of high-trajectory missiles are the roofs of structures, and the only targets oflow-trajectory missiles are the walls of structures. (Since the containment dome has aprojected area in both plan and elevation views, it is a target for both types of missiles.)

3. Interior disks (disks 1 through 4) may have trajectories up to 5 degrees off the plane ofrotation. End disks (disk 5) may have trajectories from 5 degrees to 25 degrees off the planeof rotation, but only in the direction of the hood end.

4. For the purpose of calculating strike probabilities, the missile is assumed to be a point object.

5. The origin of interior disk missiles is located at the center of the hood, and the origins of theend disk missiles are assumed to be 6 ft. to either side of the hood center.

6. If a missile perforates a barrier, it is assumed to follow the same trajectory it had beforestriking the barrier, but the kinetic energy is reduced (i.e., the barrier is not a scatteringsource). If the missile does not perforate a barrier, ricochets are not considered.

7. In a barrier perforation analysis, only the velocity normal to the barrier surface is relevant.

8. The selection of targets assumed that no earthquake or pipe rupture occurs concurrently withthe postulated failure of the turbine.

9. The column 9 line as shown on the site plan, Reference Drawing 1, is the divider betweenUnits 1 and 2.

10. For the destructive overspeed case, it is assumed that the failure rate of any one of the 20low-pressure turbine disks is 1/20 of the total.

11. It is assumed that for every fragment created by a low-pressure disk failure, there will becorresponding cylinder and blade ring fragments as detailed in References 7 and 8.

12. When using the modified NDRC formula for calculating missile perforation, it is sufficient touse the average missile “diameter,” since the perforation equation is reasonably insensitive tothis parameter in the normal range of turbine missile diameters.

10.2.1.5 Targets Eliminated Based on Redundancy

Standard Review Plan (SRP) Section 3.5.1.3, Turbine Missiles, provides the followingposition on redundancy.

Adequate protection will also be identified with targets which are redundant and sufficientlyindependent (e.g., by separation distance, barriers) such that a turbine failure could notcomprise two or more members of a redundant train.


This position was employed in the North Anna systems review to eliminate the followingessential systems as potential targets of turbine missiles:

1. Emergency diesel generators

a. Protected from low-trajectory missiles by the turbine pedestal.

b. Only one of the two diesel generators provided for each unit is required to meet all safetyrequirements.

c. A vertical concrete wall separates each diesel generator and provides adequate protectionagainst multiple failures or secondary missiles due to a single high-trajectory missile.

2. Service water system and auxiliary service water system

These two systems exit the service building at 180 degrees to each other and are bothindependent and redundant. Either system acting alone can handle all safety-related servicewater requirements.

10.2.1.6 Intermediate Barriers

In addition to the protection provided by the structures housing essential systems, thefollowing intermediate structures and components were evaluated for their shielding potential.

1. Turbine Support Pedestal: The turbine support consists of 8 feet of reinforced concrete in thearea of the low-pressure hoods. This barrier was judged adequate to stop all turbine missiles,thereby making it impossible for any missile ejected below the horizontal to present a hazard.They are either directed into the turbine support or more sharply downward where there areno essential systems.

2. Turbine Room Floor: This floor acts as a deflecting shield for those missiles ejected within 1or 2 degrees of horizontal. These missiles will slide along the operating floor but will notperforate it because of the extremely shallow angle of impact.

3. Moisture Separators: The moisture separators are close to the turbine and must be penetratedby some postulated low-trajectory missiles. These separators will stop some missiles andsignificantly reduce the kinetic energy of others. The following method is used to evaluatemissiles striking the moisture separators:

a. The Ballistic Research Laboratory (BRL) formula (Reference 11) is used to define therequired perforation energy. This energy is assumed equal to twice the energy required toperforate the 1.25-inch-thick shell of the moisture separator (i.e., perforation must occuron entering and exiting).

b. If the striking missile’s energy exceeds that required for perforation, it is assumed tocontinue on its original path with its energy reduced by an amount equal to its perforationenergy from step (a).


10.2.1.7 Overall Probability Calculation

Turbine missile information provided by Westinghouse (References 1-3, 7, & 8) wasapplied to the two units shown in Reference Drawing 1 using the previously detailed procedure.The resulting total damage probability (P4) for each unit/trajectory case is summarized in thetables as follows:

1. Table 10.2-2: Gives breakdown of total damage probability (P4) associated with eachpostulated failure speed for 1 year of continuous operation using criterion A.1

2. Table 10.2-3: Gives breakdown of total damage probability (P4) associated with eachpostulated failure speed for 1 year of continuous operation using criterion B.1

3. Table 10.2-4: Gives breakdown of total damage probability (P4) associated with eachpostulated failure speed for 2 years of continuous operation using criterion A.1

4. Table 10.2-5: Gives breakdown of total damage probability (P4) associated with eachpostulated failure speed for 2 years of continuous operation using criterion B.2

5. Table 10.2-6: This table combines the results of Tables 10.2-2 through 10.2-5 with twopossible realistic scabbing damage probabilities (P3S) of 0.05 and 0.10. P3S is theprobability for ensuing damage to safety-related equipment if a missile strike results inscabbing without perforation.

6. Table 10.2-7: This table contains a listing of the critical plant regions for the Unit 1 turbinefor the postulated high- and low- trajectory missiles.

7. Table 10.2-8: Same as Table 10.2-7 for the Unit 2 turbine.

10.2.1.8 Conclusion

The following conclusion can be made from the values given in Table 10.2-6 and the use ofWestinghouse Turbine Disk Inspection Criteria (deterministic) for operating reactors. Theprobability (P4) of significant damage to critical plant regions due to a postulated turbine failure issufficiently low that design changes of the plant against turbine missile effects need not beconsidered.

Vepco will inspect the turbine disk for cracking by performing an ultrasonic inspection onthe low-pressure turbine at North Anna Units 1 and 2 on a schedule calculated by Reference 6.Vepco will base its inspection intervals on the disk that gives the shortest interval for the unit

1. Criteria A and B, as used in Tables 10.2-2 through 10.2-5, are discussed in Section 10.2.1.3. Criterion A is the present conservative NRC approach that equates the initiation of scabbing within a safety-related cubicle with a damage probability of 1.0, and criterion B neglects scabbing damage if missile perforation is presented.

2. Criteria A and B, as used in Tables 10.2-2 through 10.2-5, are discussed in Section 10.2.1.3. Criterion A is the present conservative NRC approach that equates the initiation of scabbing within a safety-related cubicle with a damage probability of 1.0, and criterion B neglects scabbing damage if missile perforation is presented.


involved, regardless of whether or not that disk would be contained by the casing, in the event of aturbine missile generation.

10.2 REFERENCES

1. Westinghouse Electric Corporation, Analysis of the Probability of the Generation and Strikeof Missiles from a Nuclear Turbine, 1974.

2. Westinghouse Electric Corporation, Results of Probability Analyses of Disc Rupture andMissile Generation, North Anna 2, CT-24860, Revision 1, 1981.

3. Westinghouse Electric Corporation, Results of Probability Analyses of Disc Rupture andMissile Generation, North Anna 1, CT-24822, Revision 1, 1981.

4. Westinghouse Electric Corporation, Procedures for Estimating the Probability of SteamTurbine Disc Rupture from Stress Corrosion Cracking, WSTG-1-NP, 1981.

5. Westinghouse Electric Corporation, Missile Energy Analysis Methods for Nuclear SteamTurbines, WSTG-2-NP, 1981.

6. Westinghouse Electric Corporation, Criteria for Low Pressure Nuclear Turbine DiscInspection (Westinghouse proprietary), 1981.

7. Westinghouse Electric Corporation, Turbine Missile Report, North Anna 1, CT-24821, 1980.

8. Westinghouse Electric Corporation, Turbine Missile Report, North Anna 2, CT-24859, 1980.

9. S. H. Bush, Probability of Damage to Nuclear Components Due to Turbine Failures, NuclearSafety, Vol. 14, No. 3, 1973.

10. G. E. Sliter, Assessment of Empirical Concrete Impact Formulas, Journal of StructuralDivision, May 1980.

11. Department of the Army, Fundamentals of Protection Design, TM-5-855-1, July 1965.

12. Westinghouse Electric Corporation evaluation report, Evaluation of Turbine Missile EjectionProbability Resulting from Extending the Test Interval of Interceptor and Reheat Stop Valvesat North Anna Units 1 and 2, dated December 1994.

13. Westinghouse Electric Corporation report, WCAP-11525, Probabilistic Evaluation ofReduction in Turbine Valve Test Frequency, dated June 1987.

14. Westinghouse Electric Corporation, WCAP-14732, Probabilistic Analysis of Reduction inTurbine Valve Test Frequency for Nuclear Plants with Westinghouse BB-296 Turbines withSteam Chests, dated September 1996.

15. Westinghouse Electric Corporation, WCAP-16501-P, Extension of Turbine Valve TestFrequency Up to 6 Months for BB-296 Siemens Power Generation (Westinghouse) Turbineswith Steam Chests, Revision 0, dated February 2006.


10.2 REFERENCE DRAWINGS

The list of Station Drawings below is provided for information only. The referenced drawings are not part of the UFSAR. This is not intended to be a complete listing of all Station Drawings referenced from this section of the UFSAR. The contents of Station Drawings are controlled by station procedure.

Drawing Number Description

1. 11715-FY-1A Plot Plan, Units 1 & 2

2. 11715-FM-4D Machine Location: Turbine Area, Sections, Sheet 1


Table 10.2-1FAILURE ANALYSIS OF GLAND STEAM SEAL SYSTEM COMPONENTS

Component Malfunction Remarks

Main supply valve Failure of diaphragm or air supply

Valve opens. The pressure in the header system increases to 300 psig, at which point the safety valve would open, limiting the maximum pressure buildup to 485 psig. The gland supply valves and the high-pressure spillover valve would continue to maintain the prescribed pressure at each gland. A pressure transmitter and motor-operated bypass and isolation valves are provided to permit manual or remote correction of this situation. No adverse effect is anticipated.

Gland supply valve Failure of diaphragm or air supply

Valve opens. These valves are sized so that when they are fully open and with 140-psia steam pressure maintained in the supply header, the pressure in the gland case will only increase to 21 psia. This condition will not cause any steam leakage to the atmosphere since the gland suction piping is sized to accommodate the resulting leakage. No adverse effect is anticipated.

High-pressure spillover valve

Failure of diaphragm or air supply

Valve closes. If the failure should happen at starting or at low loads, the pressure in the gland will increase, but the gland will continue to function properly. If failure occurs at a turbine load point in excess of 10% to 15%, the glands will leak steam to the turbine building atmosphere At high loads, the pressure in the gland header will increase to a point that will result in the opening of a safety valve. A pressure transmitter and motor-operated shutoff and bypass valves are supplied for manual or remote control in the event of this failure. The effects and consequences of this occurrence are the same as discussed in Section 15.3.2 for minor secondary pipe breaks.


Steam supply pressure

Supply line rupture Steam would be released to the turbine building. Loss of supply steam would also cause eventual loss of vacuum and subsequent turbine trip. The consequences of a break in the supply line to the gland seal system are discussed in Section 15.3.2. A supply line break would be indicated in the main control room by a pressure indicator. A loss of supply steam causes eventual loss of condenser vacuum and subsequent turbine trip, which is discussed in Section 15.2.7.

Table 10.2-1FAILURE ANALYSIS OF GLAND STEAM SEAL SYSTEM COMPONENTS



Table 10.2-2TOTAL DAMAGE PROBABILITY FOR 1 YEAR OFCONTINUOUS OPERATION USING CRITERION A

Unit Trajectory

Percentage of Rated Speed

100 120 191 Total

Unit 1

Low trajectory 2.33 × 10-7 4.002 × 10-9 5.710 × 10-7 8.080 × 10-7

High trajectory

Due to Unit 1 turbine

1.446 × 10-7 8.855 × 10-10 5.595 × 10-8


6.978 × 10-9 2.085 × 10-10 2.447 × 10-9

Total high trajectory 1.516 × 10-7 1.094 × 10-9 5.84 × 10-8 2.111 × 10-7

Unit 2

Low trajectory 1.90 × 10-7 3.293 × 10-9 5.579 × 10-7 7.514 × 10-7

High trajectory


1.257 × 10-8 2.349 × 10-10 2.326 × 10-9


7.224 × 10-8 9.002 × 10-10 2.793 × 10-8


Note: P1 values from References 1, 2, and 3.


Table 10.2-3TOTAL DAMAGE PROBABILITY FOR 1 YEAR OFCONTINUOUS OPERATION USING CRITERION B

Unit Trajectory


100 120 191 Total

Unit 1

Low trajectory 1.937 × 10-14 4.835 × 10-15 4.763 × 10-7 4.763 × 10-7

High trajectory


1.197 × 10-9 9.744 × 10-11 1.588 × 10-9


2.861 × 10-10 7.128 × 10-11 1.641 × 10-9


Unit 2

Low trajectory 1.026 × 10-11 6.8322 × 10-13 4.686 × 10-7 4.686 × 10-7

High trajectory


2.617 × 10-9 8.705 × 10-11 1.243 × 10-9


4.867 × 10-9 1.258 × 10-10 1.841 × 10-9




Table 10.2-4TOTAL DAMAGE PROBABILITY FOR 2 YEARS OFCONTINUOUS OPERATION USING CRITERION A

Unit Trajectory


100 120 191 Total

Unit 1

Low trajectory 1.26 × 10-5 1.619 × 10-7 1.142 × 10-6 1.390 × 10-5

High trajectory


8.225 × 10-6 3.720 × 10-8 1.119 × 10-7


3.493 × 10-7 8.603 × 10-9 4.894 × 10-9


Unit 2

Low trajectory 1.086 × 10-5 1.384 × 10-7 1.116 × 10-6 1.211 × 10-5

High trajectory


7.348 × 10-7 1.004 × 10-8 4.652 × 10-9


4.010 × 10-6 3.715 × 10-8 5.586 × 10-8




Table 10.2-5TOTAL DAMAGE PROBABILITY FOR 2 YEARS OFCONTINUOUS OPERATION USING CRITERION B

Unit Trajectory


100 120 191 Total

Unit 1

Low trajectory 1.686 × 10-11 3.166 × 10-12 9.526 × 10-7 9.560 × 10-7

High trajectory


7.036 × 10-8 4.084 × 10-9 3.176 × 10-9


1.632 × 10-8 2.936 × 10-9 3.282 × 10-9


Unit 2

Low trajectory 2.415 × 10-9 1.047 × 10-10 9.372 × 10-7 9.397 × 10-7

High trajectory


1.528 × 10-7 3.687 × 10-9 2.486 × 10-9


2.730 × 10-7 5.167 × 10-9 3.684 × 10-9




Tabl

e 10

.2-6

TOT

AL

PR

OB

AB

ILIT

Y F

OR

EA

CH

UN

IT-T

RA

JEC

TO

RY

CA

SE

P3S

= 5

%P3

S =

10%

1Y

eara

2Y

eara

3Y

eara

1Y

eara

2Y

eara

Uni

t 1 Hig

h tr

ajec

tory

1.51

9×

10-8

5.32

0×

10-7

3.74

6×

10-6

2.55

0×

10-8

9.

639

×10

-7

Low

traj

ecto

ry4.

929

×10

-71.

600

×10

-85.

883

×10

-65.

095

×10

-72.

247

×10

-6

Uni

t 2 Hig

h tr

ajec

tory

1.60

5×

10-8

6.61

4×

10-7

3.57

4×

10-6

2.13

2×

10-8

8.82

0×

10-7

Low

traj

ecto

ry4.

827

×10

-71.

498

×10

-65.

378

×10

-64.

969

×10

-72.

057

×10

-6

a.In

spec

tion

inte

rval

bas

ed o

n ac

tual

ope

rati

ng h

ours

ass

umin

g th

e in

spec

tion

inte

rval

s fo

r bo

th u

nits

coi

ncid

e.


Tabl

e 10

.2-7

TU

RB

INE

TA

RG

ET

DIS

TA

NC

ES

AN

D I

MPA

CT

AR

EA

S -

UN

IT 1

TU

RB

INE

Low

-Pre

ssur

e H

ood

1L

ow-P

ress

ure

Hoo

d2

Cri

tica

lPla

ntR

egio

nIm

pact

Are

a (f

t2 )r

min

. (ft

)r

max

. (ft

)r

min

. (ft

)r

max

. (ft

)Y

(ft

)

Hig

h-tr

ajec

tory

mis

sile

s

Rea

ctor

con

tain

men

t, U

nit 1

11,4

5720

230

320

433

536

Rea

ctor

con

tain

men

t, U

nit 2

11,4

5732

145

229

542

636

Mai

n st

eam

val

ve h

ouse

, Uni

t 115

4616

970

611

920

522

Mai

n st

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ve h

ouse

, Uni

t 215

4630

436

227

333

122

Fuel

bui

ldin

g18

9929

735

928

233

9-1

5

Aux

iliar

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edw

ater

pum

p ho

use,

Uni

t 122

4126

033

527

635

0-2

0

Aux

iliar

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edw

ater

pum

p ho

use,

Uni

t 222

4144

951

141

848

2-2

0

Aux

iliar

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ildi

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5917

133

515

431

212

Fuel

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pum

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use

and

tank

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763

053

560

9-3

0

Gas

eous

was

te d

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tank

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832

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5

Aux

iliar

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edw

ater

pip

e tu

nnel

, Uni

t 177

019

025

820

727

0-3

5

Aux

iliar

y fe

edw

ater

pip

e tu

nnel

, Uni

t 277

039

843

836

540

8-3

5

Cab

le tu

nnel

, Uni

t 187

114

719

414

418

7-3

3

Cab

le tu

nnel

, Uni

t 287

127

331

424

228

4-3

3

Cab

le v

ault

, Uni

t 115

0018

624

518

925

3-8

Cab

le v

ault

, Uni

t 215

0026

930

229

832

5-8

Con

trol

roo

m a

nd e

mer

genc

y sw

itch

gear

/rel

ay r

oom

17,7

0275

261

7529

3-1

3

Not

es:

1.A

ll r

val

ues

are

take

n fr

om th

e ce

nter

of

the

low

-pre

ssur

e ho

od.

2.R

efer

to F

igur

e 10

.2-3

for

the

defi

nitio

ns o

f r

and

y.

3.“M

in.”

and

“m

ax.”

ref

er to

min

imum

and

max

imum

dis

tanc

es, r

espe

ctiv

ely.


Tabl

e 10

.2-7

(con

tinue

d)T

UR

BIN

E T

AR

GE

T D

IST

AN

CE

S A

ND

IM

PAC

T A

RE

AS

- U

NIT

1 T

UR

BIN

E

Cri

tica

lPla

ntR

egio

nIm

pact

Are

a (f

t2 )L

P1

r (f

t)L

P2

r (f

t)Y

min

. (ft

)Y

max

. (ft

)

Low

-tra

ject

ory

mis

sile

s

Rea

ctor

con

tain

men

t, U

nit 1

9185

200

200

-680

Rea

ctor

con

tain

men

t, U

nit 2

9185

----

----

Mai

n st

eam

val

ve h

ouse

, Uni

t 118

2516

916

9-1

722

Mai

n st

eam

val

ve h

ouse

, Uni

t 218

25--

----

--

Con

dens

ate

stor

age

tank

, Uni

t 110

0031

733

1-3

3 -

2

Con

dens

ate

stor

age

tank

, Uni

t 210

00--

----

--

Ven

tila

tion

in a

uxil

iary

bui

ldin

g14

6--

198

-14

19

Not

es:

1.A

ll r

val

ues

are

take

n fr

om th

e ce

nter

of

the

low

-pre

ssur

e ho

od.

2.R

efer

to F

igur

e 10

.2-3

for

the

defi

nitio

ns o

f r

and

y.

3.“M

in.”

and

“m

ax.”

ref

er to

min

imum

and

max

imum

dis

tanc

es, r

espe

ctiv

ely.


Tabl

e 10

.2-8

TU

RB

INE

TA

RG

ET

DIS

TA

NC

ES

AN

D I

MPA

CT

AR

EA

S -

UN

IT 2

TU

RB

INE

Low

-Pre

ssur

e H

ood

1L

ow-P

ress

ure

Hoo

d2

Cri

tica

lPla

ntR

egio

nIm

pact

Are

a (f

t2 )r

min

. (ft

)r

max

. (ft

)r

min

. (ft

)r

max

. (ft

)Y

(ft

)

Hig

h-tr

ajec

tory

mis

sile

s

Rea

ctor

con

tain

men

t, U

nit 1

11,4

5731

044

133

746

836

Rea

ctor

con

tain

men

t, U

nit 2

11,4

5720

233

320

433

536

Mai

n st

eam

val

ve h

ouse

, Uni

t 115

4629

034

932

238

022

Mai

n st

eam

val

ve h

ouse

, Uni

t 215

4616

920

416

921

022

Fuel

bui

ldin

g18

9928

232

629

334

3-1

5

Aux

ilia

ry f

eedw

ater

pum

p ho

use,

Uni

t 122

4143

649

846

852

8-2

0

Aux

ilia

ry f

eedw

ater

pum

p ho

use,

Uni

t 222

4126

634

125

332

8-2

0

Aux

ilia

ry b

uild

ing

6259

163

325

184

349

12

Fuel

-oil

pum

p ho

use

and

tank

s31

4445

052

144

651

6-3

0

Gas

eous

was

te d

ecay

tank

s68

833

837

435

539

2-3

5

Aux

ilia

ry f

eedw

ater

pip

e tu

nnel

, Uni

t 177

038

141

941

545

0-3

5

Aux

ilia

ry f

eedw

ater

pip

e tu

nnel

, Uni

t 277

019

626

718

225

7-3

5

Cab

le tu

nnel

, Uni

t 187

126

028

529

231

5-3

3

Cab

le tu

nnel

, Uni

t 287

114

519

015

420

1-3

3

Cab

le v

ault,

Uni

t 115

0028

531

531

534

0-8

Cab

le v

ault,

Uni

t 215

0018

724

919

425

9-8

Con

trol

roo

m a

nd e

mer

genc

y sw

itch

gear

/rel

ay r

oom

17,7

0281

334

101

369

-13

Not

es:

1.A

ll r

val

ues

are

take

n fr

om th

e ce

nter

of

the

low

-pre

ssur

e ho

od.

2.R

efer

to F

igur

e 10

.2-3

for

the

defi

niti

ons

of r

and

y.

3.“M

in.”

and

“m

ax.”

ref

er to

min

imum

and

max

imum

dis

tanc

es, r

espe

ctiv

ely.


Tabl

e 10

.2-8

(co

ntin

ued)

TU

RB

INE

TA

RG

ET

DIS

TA

NC

ES

AN

D I

MPA

CT

AR

EA

S -

UN

IT 2

TU

RB

INE

Cri

tica

lPla

ntR

egio

nIm

pact

Are

a (f

t2 )L

P1r

(ft)

LP2

r (f

t)Y

min

. (ft

)Y

max

. (ft

)

Low

-tra

ject

ory

mis

sile

s

Rea

ctor

con

tain

men

t, U

nit 1

9185

----

----

Rea

ctor

con

tain

men

t, U

nit 2

9185

200

200

-680

Mai

n st

eam

val

ve h

ouse

, Uni

t 118

25--

----

--

Mai

n st

eam

val

ve h

ouse

, Uni

t 218

2516

916

9-1

722

Con

dens

ate

stor

age

tank

, Uni

t 110

00--

----

--

Con

dens

ate

stor

age

tank

, Uni

t 210

0032

231

0-3

2 -

2

Ven

tilat

ion

in a

uxil

iary

bui

ldin

g14

6--

----

--

Not

es:

1.A

ll r

val

ues

are

take

n fr

om th

e ce

nter

of

the

low

-pre

ssur

e ho

od.

2.R

efer

to F

igur

e 10

.2-3

for

the

defi

niti

ons

of r

and

y.

3.“M

in.”

and

“m

ax.”

ref

er to

min

imum

and

max

imum

dis

tanc

es, r

espe

ctiv

ely.


Figu

re10

.2-1

TO

TA

L L

OW

TR

AJE

CT

OR

Y T

UR

BIN

E M

ISSI

LE

EN

VE

LO

PE

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

rum

, dia

m q

uis

tinci

dunt

ele

men

tum

, sem

orc

i bib

endu

m li

bero

, ut e

lem

entu

m

just

o m

agna

at a

ugue

. Aliq

uam

sap

ien

mas

sa, f

auci

bus

ac, e

lem

entu

m n

on, l

aore

et n

ec, f

elis

. Ves

tibul

um a

ccum

san

sagi

ttis

ipsu

m. I

n ul

lam

corp

er, d

ui s

ed c

ursu

s eu

ism

od, a

nte

wis

i dap

ibus

ligu

la, i

d rh

oncu

s ip

sum

mi a

t tel

lus.

Cla

ss a

pten

t ta

citi

soci

osqu

ad

litor

a to

rque

nt p

er c

onub

ia n

ostr

a, p

er in

cept

os h

ymen

aeos

. Qui

sque

rho

ncus

wis

i vita

e do

lor.

Etia

m

elei

fend

. Int

eger

impe

rdie

t veh

icul

a an

te. S

ed in

arc

u et

odi

o ac

cum

san

port

a. A

enea

n m

i. V

ivam

us n

on o

rci v

itae

urna

al

ique

t ulla

mco

rper

. Cla

ss a

pten

t tac

iti s

ocio

squ

ad li

tora

torq

uent

per

con

ubia

nos

tra,

per

ince

ptos

hym

enae

os. I

n fr

ingi

lla

ligul

a ve

l odi

o. In

hac

hab

itass

e pl

atea

dic

tum

st. E

tiam

tem

pus

lacu

s ac

arc

u. P

raes

ent n

on li

bero

.


Figu

re10

.2-2

T

UR

BIN

E M

ISSI

LE

S

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

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Figure 10.2-3 TURBINE MISSILE REFERENCE SYSTEM


Figure 10.2-4 TOP VIEW OF IDEALIZED TARGET


Figure 10.2-5 SIDE VIEW OF IDEALIZED TARGET


10.3 MAIN STEAM SYSTEM

10.3.1 Design Basis

See Section 10.1 for a general description of the design basis for the steam and powerconversion system. Additional relevant information is contained in Section 5.5, which discussesthe steam generator.

Each of the three main steam pipes is designed in accordance with the ASME Code forPressure Piping, ANSI B31.1-1967, except for that portion designated as Seismic Class I piping,which is designed in accordance with the Code for Nuclear Power Piping, ANSI B31.7 (seeSection 3.2.2).

The main steam safety valves are designed in accordance with the functional requirementsof ASME III-1968 Edition with Addenda through Winter 1970.

The steam dump system is designed to take the excess steam generated from load changesexceeding 10% step or 5%/minute and is sized to take the flow resulting from a 50% loadrejection. A 50% load rejection results in a 40% steam dump to the condenser with the remainingportion of the load rejection accommodated by the nuclear steam supply system. This flow isdivided equally through eight steam dump valves. An uncontrolled plant cooldown caused by asingle valve sticking open is minimized by the use of a group of valves installed in parallel insteadof a single valve. The steam dump system will also permit a turbine and/or reactor trip from fullload without lifting the steam generator safety valves.

Each steam generator is provided with one safety-grade, seismically supported, atmosphericdump valve. The atmospheric dump valves are each sized to pass approximately 10% of themaximum calculated steam flow from each steam generator. The design function of theatmospheric dump valves is to provide controlled relief of the main steam flow. Each valve iscapable of being fully opened and closed, either remotely or by local manual operation.

The main steam piping supports have been analyzed for turbine trip forces as well as forseismic forces. In addition, the system has been stress analyzed for the forces and moments thatresult from thermal expansion. The main steam piping within the containment annulus has beenreviewed for possible pipe rupture, and sufficient supports and guides have been provided toprevent damage to the containment liner and adjacent piping.

10.3.2 System Description

The main steam system is shown in Figure 10.3-1 and Reference Drawings 1 and 2.

Steam is conducted individually from each of the three steam generators within the reactorcontainment through a steam flow meter (venturi) interconnected with its three-element feedwatercontrol system, a swing-disk-type trip valve and an angle-type nonreturn valve into a commonheader. Figures 10.3-2 and 10.3-3 show an outline of these valves, including material


identification, dimensions, steam conditions, and flows. The steam passes from the header to theturbine throttle stop valves and governor valves.

Each steam generator is provided with a flow limiting device that is installed integral to thesteam outlet nozzle. The steam nozzle flow limiting devices were installed during the steamgenerator replacement modification to limit the blowdown rate of steam from the steam generatorin the unlikely event of a main steam line rupture. A venturi tube flow restrictor is located in themain steam line downstream of each steam outlet nozzle. These flow restrictors were installedduring original construction of the plant and, prior to the installation of the steam nozzle flowlimiting devices, functioned both as the flow limiters during a postulated main steam line rupturedownstream of the venturis and as flow elements for steam flow measurement during normaloperation of the unit. The venturi currently functions only as a flow element for steam flowmeasurement, since the steam nozzle flow limiting device is upstream of and has a slightlysmaller total throat cross sectional area.

Design bases for the main steam flow restrictors are as follows:

1. To provide plant protection in the event of a main steam line rupture. In such an event, theflow restrictor limits steam flow rate from the break, which in turn limits the cooling rate ofthe primary system. This precludes departure from nucleate boiling (DNB) and minimizesfuel clad damage, as discussed in Chapter 15.

2. To reduce thrust forces on the main steam piping in the event of a steam line rupture, therebyminimizing the potential for pipe whip.

3. To minimize unrecovered pressure loss across the restrictor during normal operation.

4. To withstand the number of pressure and thermal cycles experienced in the life of the plant.

5. To maintain flow restrictor integrity in the event of a double-ended severance of a main steamline immediately downstream of the flow restrictor.

The main steam line flow element has the additional design requirement of providing thepressure differential necessary for steam flow measurement.

Each steam nozzle flow limiting device consists of an assembly of seven bundled venturis,each having a nominal throat diameter of 6 inches, installed integral to the main steam outletnozzle of each steam generator. The steam nozzle flow limiting device does not restrict steamflow under normal conditions, but would prevent a rapid depressurization of the steam generatorby choking the steam flow, should a main steam line break (MSLB) accident occur.

Each main steam line flow element is composed of a nominal 16-inch diameter throatventuri nozzle section and a carbon steel discharge cone and is permanently welded inside alength of main steam piping by a circumferential weld at the discharge end of the venturi. Themain steam line flow elements provide the pressure differential necessary for steam-flowmeasurement using upstream and venturi throat pressure taps.


The swing-disk-type trip valves in series with the nonreturn valves contain swinging disksthat are normally held up out of the main steam flow path by air cylinder operators. If a steam linepipe rupture occurs, as discussed in Section 15.4.2, downstream of the trip valves, an excess flowsignal from the steam flow meter, combined with low T average or low steam line pressure in twoout of three matrices, will release the air pressure on the air cylinders and spring action will causethese valves to trip closed, thus stopping the flow of steam through the steam lines. Valve closurechecks the sudden and large release of energy that is in the form of main steam, therebypreventing rapid cooling of the reactor coolant system and ensuing reactivity insertion. Trip valveclosure also ensures a supply of steam to the turbine drive of the auxiliary steam generator feedpump described in Section 10.4.3.

The nonreturn valves prevent reverse flow of steam in the case of accidental pressurereduction in any steam generator or its piping and also provide a motor-operated manual shutoffof steam from the respective steam generator.

If a steam line breaks between a trip valve and a steam generator, the affected steamgenerator will continue to blow down. The nonreturn valve in the line prevents blowdown fromthe other steam generators. This would be the worst steam-break accident and is discussed inSection 15.4.2. The main steam trip valves provide backup for the nonreturn valve, by ESFactuation, to prevent blowdown from intact loop steam generators through a ruptured pipebetween the affected steam generator and its trip valve.

A total of five ASME Code safety valves are located on each main steam line outside thereactor containment and upstream of the nonreturn valves. The five valves provide each headerwith a total relieving capacity of 4,275,420 lb/hr. The setpoints, setpoint tolerances, and relievingcapacities of each safety valve are given as follows:

Actual total capacity for five valves 4,275,420 lb/hrRequired total capacity for five valves 4,255,542 lb/hrExcess capacity 19,878 lb/hr

Mark NumberSetpoint

Pressure (psig)

Capacity, Eachat SetpointPressure

Capacity, Eachat Setpoint1135 psig

SetpointPressure

Tolerance

SV-MS101A,B,C 1085 817,883 855,084 ±1% a

SV-MS102A,B,C 1095 825,323 855,084 ±1%

SV-MS103A,B,C 1110 836,483 855,084 ±1%

SV-MS104A,B,C 1120 843,924 855,084 ±1%

SV-MS105A,B,C 1135 855,084 855,084 ±1%

a. Technical Specifications allow a ±3% “as-found” lift setpoint tolerance and a ±1% “as-left” setpoint tolerance. The lift setting pressure shall correspond to ambient conditions of the valve at nominal operating temperature and pressure.


In the case of one or more inoperable main steam safety valve(s) (MSSVs), the TechnicalSpecifications allow operation of Units 1 and 2 at reduced power levels. The reduction in reactorpower (and associated reduction in neutron flux) is required to ensure MSSV capacity is sufficientto prevent secondary side pressure from exceeding 110% of the design.

The steam dump system dumps excess steam generated by the sensible heat in the core andthe reactor coolant system directly to the condensers by means of two main steam bypass lines,each of which contains a bank of four steam dump valves arranged in parallel.

All or several of the dump valves open under the following conditions provided the variouspermissive interlocks are satisfied:

1. On a large step-load decrease, the steam dump system creates an artificial load on the steamgenerators, thus enabling the nuclear steam supply system to accept a 50% load rejectionfrom the maximum capability power level without reactor trip or atmospheric dump throughthe main steam safety valves. An error signal exceeding a set value of reactor coolant Tavgminus Tref fully opens all valves in less than 5 seconds. Tref is a function of load and is setautomatically. The valve closes automatically as reactor coolant conditions approach theirprogrammed setpoint for the new load.

2. On a turbine trip with reactor trip, the pressures in the steam generators rise. To preventoverpressure without main steam safety valve operation, the steam dump valves open,discharging to the condenser for several minutes to dissipate the thermal output of the reactorwithout exceeding acceptable core and coolant conditions.

3. After a normal orderly shutdown of the turbine generator leading to unit cooldown, the steamdump valves are used to release steam generated from the sensible heat for several hours andare controlled from main steam header pressure. Unit cooldown, programmed to minimizethermal transients and based on sensible heat release, is effected by a gradual manual closingof the dump valves until the cooldown process can be transferred to the residual heat removalsystem (Section 5.5).

4. During start-up, hot standby service, or physics testing, the steam dump valves are actuatedremote manually from the main control board and are operated in the steam pressure controlmode.

All condenser steam dump valves are prevented from opening on a loss of condenservacuum or when an insufficient number of circulating water pumps are running. In this event,excess steam pressure is relieved to the atmosphere through the atmospheric steam dump valvesor the main steam safety valves. Interlocks are provided to reduce the probability of spuriousopening of the steam dump valves.

An atmospheric steam dump valve with a manually adjustable setpoint is provided on eachmain steam header upstream of the nonreturn valve outside the containment. Control air issupplied to the atmospheric dump valves from the instrument air system. Air is delivered to the


valves through a seismically qualified 2-inch header from the auxiliary building. The 2-inchheader is reduced to a 3/4-inch seismically qualified header in the main steam valve house. The3/4-inch header splits and supplies each of the valves through individual check valves. Locatedbetween the check valve and the respective atmospheric dump valve is a connection to a backupsupply tank for each of the dump valves. The seismically qualified tanks each have a volume of16.7 ft3 at 110 psig. The tanks are maintained at pressure by the instrument air header. The checkvalves prevent a loss of air from the tanks back through the instrument air header should theinstrument air system become depressurized. Electrical power to the electropneumatic controller,which controls the valve position, is provided to each valve from separate channels ofuninterruptible safety-grade power from independent station batteries. The control cablesproviding electrical signals to all three atmospheric dump valves are designated as non-safetyrelated and routed in the same non-safety related cable tray and conduit, which reflects theoriginal control grade design of this system. The relieving pressure of these valves (normally1035 psig) is individually controlled from the main control board. Each valve has a capacity of425,244 lb/hr of saturated steam at 1025 psig. The valve is normally set to discharge at a pressurelower than that of the lowest set main steam safety valve to avoid opening the safety valves.

The atmospheric steam dump valves (steam generator PORVs) can also be used to achieve acontrolled cooldown of the reactor by reducing steam generator pressure. This capability isparticularly important for recovery from a steam generator tube rupture accident. For the event tobe terminated in a timely manner, the operators must depressurize the reactor coolant system(RCS) to a value at or below the secondary side of the ruptured generator. To support thisdepressurization, the RCS must first be cooled by dumping steam from the non-rupturedgenerators. This is done via the condenser steam dump valves, if available. If a loss of offsitepower or other upset renders the condenser or condenser steam dump valves unavailable, thencooldown is achieved using the steam generator PORVs. See Section 15.4.3, Steam GeneratorTube Rupture, for further details.

In addition, a decay heat release control valve (HCV-MS104) is provided that,approximately 1/2 hour after reactor shutdown, is capable of releasing the sensible and coreresidual heat to the atmosphere via the decay heat release header. This valve is manuallypositioned from the main control board by remote control. This one valve, which is mounted onthe common decay heat release header, serves all three steam generators through 3-inchconnections on each main steam line upstream of the nonreturn valve. In addition, this valve canbe used to release the steam generated during reactor physics testing and unit hot standbyconditions. The decay heat release valve (HCV-MS104) is a 4-inch, Seismic Class I, QualityAssurance Category I valve located in the main steam valve house (see Reference Drawing 2).The valve fails in the closed position on a loss of air. A 3-inch stop-check valve is provided ineach line connecting the main steam lines to the common residual heat release header. Thesevalves are located in the main steam valve house (see Reference Drawing 2), where they areprotected from adverse environmental effects such as freezing. These stop-check valves ensurethat steam may flow to the header, but prevent reverse flow of steam.


Steam leaving the main high-pressure turbine passes through four moistureseparator-reheater units in parallel to the inlets of the low-pressure turbine cylinders. Each of thefour steam lines between the reheater outlet and low-pressure turbine (crossover piping) areprovided with a stop valve and an intercept valve in series. These valves, operated by the turbinecontrol system, function to prevent turbine overspeed. ASME Code safety valves are installed oneach moisture separator to protect the separators and crossover piping from overpressure. Thevalves are designed to pass the flow resulting from the closure of the crossover stop and interceptvalves with the main steam inlet valves wide open. Although this event is highly unlikely, thefunction of the valves that discharge to the condenser is to prevent equipment damage.

For fine control of steam flow to the moisture-separator reheater (MSR) during startup, a3-inch warm-up line and a 1-inch warm-up line, each with a manually operated valve, areinstalled in parallel around the 8-inch MSR flow control valve. A 1-inch drain line attachesupstream of the flow control valve and drains to a header for condenser penetration 55. The drainline enables water to be removed from the steam line prior to placing the line in service. Inaddition, an annubar flow element has been installed in the 8-inch reheater steam supply lineupstream of the flow control valve FCV-MS104A, B, C, or D. Attached to the flow control valveis a 1-¼-inch branch line to provide valving and piping for the local flow indicator. This providesa means of monitoring moisture separator-reheater steam supply flow.

10.3.3 Performance Analysis

The main steam line trip valves will close within 5 seconds on the receipt of a signal, andthe main steam-line nonreturn valves will close instantaneously on steam-flow reversal. Thesevalves are not required to open for plant safety.

Under accident conditions, the main steam-line trip valves will close as long as backpressure is equal to or less than the inlet pressure. The failure of the nonreturn valves will have noeffect on the ability of the trip valves to function. The nonreturn valves can also serve as stopvalves and are designed to close in 120 seconds by motor operation.

The atmospheric steam dump valves are fail-safe by going closed and staying closed on aloss of instrument air supply.

The maximum capacity of any single atmospheric steam dump valve, main steam safetyvalve, or condenser steam dump valve does not exceed 1.02 × 106 lb/hr at a pressure of 1100 psia.This limits the steam flow for any stuck-open valve to the value analyzed in Section 15.2.13.


In the event of an accident such as a main steam-line rupture either upstream or downstreamof the valves, the maximum design steam-flow rates, minimum steam quality, and pressuredifferentials for the main steam isolation valves and main steam nonreturn valves are as follows.

10.3.3.1 Potential for Unisolable Blowdown of All Three Steam Generators

A break in the decay heat release line (see Reference Drawing 2) between the decay heatrelease valve and the stop check valves upstream, or the inadvertent opening of the decay heatrelease valve could result in the unisolable blowdown of all three steam generators.

The inadvertent opening of the decay heat release valve is bounded by the analysis of theinadvertent opening of a single steam dump, relief, or safety valve, presented in Section 15.2.13.2.These valves are larger than the decay heat release valve, resulting in a larger blowdown rate anda faster reactor coolant system cooldown rate. The stop-check valves permit the isolation of flowfrom the decay heat release valve.

A break in the decay heat release line could result in a break opening area slightly largerthan the opening of a single steam dump, relief, or safety valve. Thus, the analysis presented inSection 15.2.13.3 is applicable to this situation.

Main Steam Trip Valves (TV-MS-101A, B, C)

Maximum flow 14.7 × 106 lb/hr

Minimum steam quality 94%

Maximum pressure differential 1005 psig

Main Steam Nonreturn Valves (NRV-MS-101A, B, C)

Maximum flow 16.9 × 106 lb/hr

Minimum steam quality 93%

Maximum pressure differential 1005 psig

The following information is HISTORICAL and is not intended or expected to be updatedfor the life of the plant.

10.3.3.2 Tests Ensuring Steam System Valve Integrity

In order to support assumptions that certain valves in the steam system could reliablyprevent simultaneous blowdown of more than one steam generator, the construction testsperformed on the valves are provided in Tables 10.3-1 through 10.3-4. These tests are provided“For Information Only” for the main steam trip valves, main steam nonreturn valves, steamdump valves, and turbine throttle and governor valves.


10.3.4 Tests and Inspections

The main steam-line trip valves are tested periodically in accordance with the TechnicalSpecifications.

Inservice inspection for the main steam-line trip valves is not required by ASME Code,Section XI.

The nonreturn valves will be tested during unit shutdown to verify that they are functional.

Since the decay heat release valve does not perform a safety-related function, there is noneed to perform periodic in-plant testing.

The condenser steam dump valves are normally used in station operation and do notperform a safety-related function. There is no need to perform periodic in-plant testing.

The main steam-line flow elements and the steam nozzle flow limiting devices are not a partof the steam system pressure boundary. No in-plant tests or inspections of these components areanticipated.




1. 11715-FM-070A Flow/Valve Operating Numbers Diagram: Main Steam System, Unit 1

12050-FM-070A Flow/Valve Operating Numbers Diagram: Main Steam System, Unit 2

2. 11715-FM-070B Flow/Valve Operating Numbers Diagram: Main Steam System, Unit 1

12050-FM-070B Flow/Valve Operating Numbers Diagram: Main Steam System, Unit 2


The following information is HISTORICAL and is not intended or expected to be updated for the life of the plant.

Table 10.3-1TESTS ENSURING STEAM SYSTEM INTEGRITY MAIN STEAM TRIP VALVES

The main steam trip valves were supplied by the Schutte & Koerting Company of Cornwells Heights, Pennsylvania. The main steam trip valves have had the following quality control requirements performed satisfactorily:

1. Radiographic examination of critical body areas (valve ends and bonnet).

2. Magnetic particle examination of body in areas not radiographed.

3. The valves were hydrostatically and seat leak tested.

4. A functional performance test was performed on the valves.

5. Welding and nondestructive test procedures were reviewed.

6. Welder and nondestructive test operators’ qualifications were reviewed.

7. Valve body-wall thickness was checked ultrasonically.

8. Mill test reports have been obtained for all pressure-retaining parts.

9. Valve rockshafts were liquid penetrant inspected.

10. Valve disk and pin materials were ultrasonically tested prior to machining.

11. Valve disk and pin assemblies were liquid penetrant examined.

12. Magnetic particle examination was performed on the valve tail links.

Dynamic analyses were performed on the valves by Schutte & Koerting and Stone & Webster in 1972 and resulted in the following modifications:

1. The valve disk was changed to 410 stainless steel and increased in thickness to 3 inches.

2. The valve rockshaft was changed to 410 stainless steel and its connections changed to splined.

3. Rupture disks were added to the air cylinders to prevent overstressing the rockshaft during a valve trip.

The main steam trip valves have been seismically analyzed by the vendor and the analysis reviewed by Stone & Webster.

The main steam trip valves have been protected from the effects of pipe breaks and jet impingement as described in Section 3C.5. The valves are functionally qualified for the environment.

A summary of a similar analysis on similar valves for the Beaver Valley Unit 1, Docket No. 50-334, was provided to the NRC on July 17, 1975.



Table 10.3-2TESTS ENSURING STEAM SYSTEM INTEGRITY MAIN STEAM NONRETURN

VALVES

The main steam nonreturn valves (MSNRVs) were supplied by Rockwell International Flow Control Division (Rockwell) of Pittsburgh, Pennsylvania.

These valves have had the following quality control requirements performed satisfactorily.

1. Radiographic examination of critical body areas (valve ends).

2. Magnetic particle examination of body in areas not radiographed.

3. Body hydrostatic and seat leakage tests.

4. Functional performance test.

5. Review of welding and nondestructive test procedures.

6. Review of welding and nondestructive test operators’ qualifications.

7. Ultrasonic checking of valve body-wall thickness.

8. Receipt of mill test reports for all pressure-retaining parts.

Dynamic analyses were performed on the valves by Rockwell and Stone & Webster, and the valves were found to be satisfactory.

The main steam nonreturn valves have been seismically analyzed by the vendor and the analysis reviewed by Stone & Webster.

The main steam nonreturn valves have been protected from the effects of the pipe breaks and jet impingement, as stated in Section 3C.5.1.5. Environmental considerations are discussed in Section 3C.5.1.6.



Table 10.3-3TESTS ENSURING STEAM SYSTEM INTEGRITY STEAM DUMP VALVES

The valve bodies, bonnet assemblies, and blind heads of these valves are designed in accordance with the applicable requirements of USAS B16.5 (e.g., a nominal 600 lb pressure rating that provides 1030 psig at the 650°F design). The general design conditions include the following:

1. Design life of 40 years

2. 500 open-shut cycles per year for the 40-year design life.

3. Valve assemblies designed to withstand seismic loadings equivalent to 3.0g in the horizontal direction and 2.0g in the vertical direction.

4. Bolting and nuts conforming to ASTM A193 and A194, respectively, except for the bolts and nuts in the packing gland area.

5. Hydrostatic shell tests in accordance with MSS-SP-61.

6. Pressure-retaining components surface inspected and checked by volumetric inspection of the body and bonnet.



Table 10.3-4TESTS ENSURING STEAM SYSTEM INTEGRITYTURBINE THROTTLE AND GOVERNOR VALVES

The following nondestructive tests were performed on components of the steam chest assemblies, including the throttle and governor valves:

Component Test

Steam chest body casting surfaces Magnetic particle inspection

Steam chest support fabrication a. Radiographic inspection of the welded joint of the barrel support to the body

b. Radiographic inspection of welds of inlet pipe to body

c. Magnetic particle inspection of weld joints in flexible support

d. Magnetic particle inspection of barrel support vertical seam weld, barrel support to base plate weld, and the welds for the jacketing lugs.

Inlet pipe for fabricating to steam chest body

Hydrotest (≈2100 psig) by pipe supplier

Throttle valve seat stellited overlay Liquid penetrant inspection

Throttle valve pilot valve seat insert stellited overlay

Liquid penetrant inspection

Weld joining throttle valve guide to bonnet Magnetic particle inspection

Weld joining throttle valve strainer to bonnet


Weld joining leak-off pipe connections to throttle valve bonnet

Magnetic particle inspection

Throttle valve bonnet Magnetic particle inspection

Plate for governor valve insert ring (parent metal) and subsequent assembly to governor valve plug

Ultrasonic inspection

Stellited overlay on governor valve insert ring that assembles on governor valve plug


Governor valve seat Ultrasonic inspection by forging supplier

Weld joining leakoff pipe connections to governor valve bonnet


Seal welding of pins that assemble muffler to governor valve bonnet subassembly



Component Test

Governor valve bonnet Magnetic particle inspection

Fabricated spring housing welds Magnetic particle inspection

Cast throttle valve support for linkage a. Ultrasonic inspection of vicinity of linkage pinhole areas

b. Magnetic particle inspection of surfaces

Valve springs (compression type) Magnetic particle inspection by supplier

Steam chest bodies Hydrotest (≈600 psig)

The steam chests have been analyzed for seismic loads as have the throttle valve and governor valve components. The chest supports were analyzed for 1.0g vertical and 1.5g horizontal applied at the center of the chest. Throttle valves and governor valves were analyzed for 1.0g vertical and l.5g horizontal applied to various components.

The valves are designed to close under full pressure. The throttle valves are fully unbalanced to close; the governor valves are partially unbalanced. Flow and pressure drop for each valve are in the direction of spring closing action. Therefore, the larger the pressure drop, the larger the force to close the valves.


Table 10.3-4 (continued) TESTS ENSURING STEAM SYSTEM INTEGRITYTURBINE THROTTLE AND GOVERNOR VALVES


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Figure 10.3-3 MAIN STEAM LINE NON-RETURN VALVE


Intentionally Blank


10.4 OTHER FEATURES OF STEAM AND POWER CONVERSION SYSTEM

10.4.1 Auxiliary Steam System

10.4.1.1 Design Basis

See Section 10.1.

All piping is designed in accordance with the ASME Code for Pressure Piping,ANSI B31.1-1967.

10.4.1.2 System Description

An auxiliary steam system is provided as shown in Reference Drawing 1 and 2. Theauxiliary steam supply header distributes 150 psig to 225 psig steam throughout the station forauxiliary services, including the following:

1. Boric acid batch tank.

2. Condenser air ejectors.

3. Chilled water units.

4. Flash evaporator (not used).

5. Primary-water tank heaters.

6. Gas stripper feed heaters.

7. Boron evaporator reboilers.

8. Containment vacuum ejectors.

9. Building heating.

Pressure-reducing valves at the inlet to the above items provide lower pressure whererequired.

Auxiliary steam is supplied from either the main steam or extraction steam systems,depending on turbine-generator load, or the auxiliary boilers. The steam from main steam orextraction steam contains no detectable radioactivity unless there has been gross leakage betweenthe primary and secondary sides of the steam generator.

As discussed in Section 11.4, radioactive contamination of this steam will be detected byeither the condenser air ejector monitor or the steam generator blowdown monitors. Thesemonitors will warn personnel of increasing radioactivity levels and therefore provide earlyindication of system malfunctions. Complete severance of a steam generator tube and the effectsand consequences of such an accident on this function are discussed in detail in Section 15.4.3.

Normally, the auxiliary steam supply header receives its steam from the second-pointextraction lines. During periods of low-load operation, when extraction steam pressure drops


below approximately 150 psig, steam is supplied from the main steam header through apressure-reducing valve. When both reactor units are shut down, steam is supplied to the auxiliarysteam header by the auxiliary boilers.

Condensate returning from the primary plant systems collects in a 300-gallon auxiliarysteam drain receiver, which is vented to the atmosphere. A portion of the condensate returning tothe receiver will flash to steam and be released to the atmosphere. Details of the radiologicalevaluation of this release are discussed in Chapter 11. The remaining portion of the condensatereturns is pumped to the condensate storage system. Condensate returns from the building heatingsystem are returned to the condensate storage system via separate receivers as discussed inSection 9.4.

The containment vacuum system steam ejectors are used only during start-up periods toinitially evacuate the containment. During normal operation, two mechanical vacuum pumpsmaintain the vacuum, as described in Section 6.2.6.

The condenser vacuum priming ejectors are used during start-up to draw the initialcondenser vacuum. During normal operation, the steam jet air ejectors maintain condenservacuum, as described in Section 10.4.6.

Two heating boilers, each rated at 80,000 lb/hr of steam, are provided for shutdownoperation. Each boiler is of the packaged-water-tube type. The boilers are furnished withdeaerator and feed and condensate pumps. Fuel oil is supplied to the boilers from the main oilstorage tank through motor-driven fuel-oil pumps.

10.4.1.3 Performance Analysis

A loss of normal ac power will shut down the auxiliary boilers. No services supplied byauxiliary steam are required to function as part of the engineered safety features during a loss ofstation power.

10.4.1.4 Tests and Inspections

The usage of the system during plant operation provides a continuing check of systemfunctionality status; specific periodic testing is not required.

10.4.1.5 Instrumentation Application

Auxiliary steam header pressure is monitored in the main control room.

Control switches for the auxiliary steam drain receiver pumps are local. Alarms areprovided in the main control room for auxiliary boiler trouble. More specific alarms are providedlocally.

Local instrumentation and controls are provided as required.


10.4.2 Circulating Water System


See Section 10.1.

To supply condensing and cooling water needs each unit requires 940,300 gpm of water at95°F. To provide operational flexibility, system reliability, and station economy, the waterrequirements for each unit are supplied by four pumps. Design data for these pumps (CW-P-1A,B, C, and D) are presented below:

Capacity 238,200 gpm

Head 25 ft

Design temperature 93°F

Design pressure 45 psig

Suction bell material ASTM-A48, Cl. 30

Impeller ASTM-B143-2A-M

Shaft AISI 416 SS

The temperature of the water pumped will vary between 35°F and 95°F.


The circulating water system, as shown in Figure 10.4-1 and Reference Drawing 3, issupplied from the North Anna Reservoir and provides cooling water for the main condenser.Circulating water is taken from the North Anna Reservoir on the north side of the station and afterpassing through the condenser is discharged into the Waste Heat Treatment Facility to dissipate alarge portion of the heat before returning to the reservoir.

The circulating water intake structure is an eight-bay reinforced-concrete structure. Eachbay houses one of the eight circulating water pumps for the two units. These pumps are rated at238,200 gpm at 25-foot total dynamic head when running at 250 rpm. Each pump is driven by avertical, solid-shaft, 2000-hp induction motor. Before entering the pumps, North Anna Reservoirwater passes through a trash rack at the mouth of each bay. This trash rack is serviced by amovable rake that discharges trash to a basket. A trolley beam is provided to handle the basket andits contents for dumping into collection trucks.

Trash that is less coarse is removed from the circulating water by traveling water screensupstream of each circulating pump.

The intake structure also contains two screen wash pumps for each unit and two bearingpumps common to both units. The latter provide lubricating water for the circulating water pumps


and are common for both units. One of the screen wash pumps for each unit is designed toSeismic Class I criteria. A three-way valve located in the discharge piping of this pump providesmakeup to the Service Water Reservoir and water to the screens when required.

A dedicated vertical pump located on the intake structure near the fire pump house isdesigned to provide the raw water supply for the reverse osmosis system and it also provides abackup to the screen wash pump through a normally isolated cross-connecting line.

The circulating water pumps discharge to the common concrete intake tunnel, whichconveys the circulating water to the station area, from which four buried steel pipes convey thewater to the condensers. Steel pipes convey the discharge water to a common concrete dischargetunnel, which terminates at a seal pit located at the entrance to the Waste Heat Treatment Facility.Each intake tunnel has provisions to measure circulating water flow. A manhole is also providedin the intake and discharge tunnels for maintenance, inspection, or repair. Taps located in thecondenser water boxes and discharge tunnel are provided for the vacuum priming system. Thevacuum priming system maintains vacuum assisted flow conditions by removing noncondensiblegases while the circulating water pumps are operating. This system is isolated when thecirculating water pumps are de-energized.

10.4.2.3 Performance Analysis

Three or four circulating water pumps for each unit will normally be in service dependingon the circulating water temperature. The flow resulting from four pumps inservice promotes selfcleaning of condenser tubes, but in winter months, when circulating water temperature is low,may cause excessive condenser vacuum.

Motor-operated butterfly valves are located at the condenser inlet and dischargedownstream of the condenser tube cleaning system strainer. The controls for the inlet anddischarge valves are arranged for full travel service. The intake tunnel, main condenser, dischargetunnel, and circulating water pumps are initially primed before starting the circulating pumps.This procedure is required as a means to prevent a hydraulic transient in this system. Controls arelocated in the main control room.

Motor-operated butterfly valves at the discharge of each circulating water pump areinterlocked with the motor circuits and open automatically on pump start-up and close on pumpshutdown.

A loss of normal ac power causes the four circulating water pumps to shut down.

An analysis of the complete rupture of a main condenser circulating water expansion jointhas been performed to assess the effect of subsequent flooding on safety-related systems andcomponents. Figure 10.4-2 indicates turbine building flood levels at various times following sucha rupture. The limited flooding conditions possible from a rupture of a condensate line in theturbine building (or in other structures housing portions of the system) are less severe than thoseof the postulated circulating water expansion joint rupture mentioned above, because of the


slower flooding rate and the ability of the operator to take action to limit the amount of flooding.The protection of essential systems described below also applies for a condensate line rupture.

Complete protection of essential systems and components has been provided by locatingwatertight barriers up to Elevation 257 ft. 0 in. around equipment rooms and pipe chasesimportant to safety. The three doors connecting the turbine building and safety-related equipmentrooms, emergency switchgear rooms, and air conditioning chiller rooms (Units 1 and 2) have beenprovided with 3-foot-high flood barriers. Where necessary, vital electrical cable duct openingshave been sealed. There are no passageways, pipe chases, or cableways below Elevation 257 ft.that can connect the flooded space to other safety-related areas except for drain lines, which havebeen provided with backflow preventers.

The circulating water pumps will be automatically tripped in the event that the water level inthe turbine building is greater than 1 foot above the 254-foot elevation floor level. The controlsystem is based on a total of six level switches. The level switches are arranged in three sets oftwo. Each set is distributed about the turbine building 254-foot elevation. A matrix of two out ofthree switches, one switch from each of the three sets, trips the four circulating water pumps. On apump trip signal the pump discharge valves will close due to a pump valve interlock. A matrix oftwo-out-of-three signals from the other group of three switches will result in a direct signal to thedischarge valves to close. The closing of the discharge valves will prevent additional flow fromgetting to the point of rupture, even should the pumps continue to run. The automatic trip of thepumps and a high-water-level alarm will be shown on annunciator displays on the main controlboard. The control arrangement was designed to permit on-line testing of each individual levelswitch, its output signal, and the matrix output trip signal. These level instruments, though not apart of the safety-related protection system, meet the single failure and testability requirements ofIEEE-279.

In addition, there are two level switches in the condenser tube cleaning pit that are at a lowerlevel than the turbine building floor. The signal from either one of the two switches will alert theoperator to an abnormal water level in the turbine building as excess water from the floor willflow into these pits. The control room operator, on seeing the three alarms occur in rapidsuccession, will check to see if the circulating water pumps are still running. If the pumps are stillrunning, as indicated by the lights or ammeters on the intake structure control board, the operatorwill then close the condenser inlet or outlet water box valves, which will shut in 80 seconds,stopping flow, and will also shut down all four circulating pumps as soon as valve travel starts.The condenser inlet and outlet valves are designed to shut against full pump flow.

If the pumps were to continue to run, the operator would trip the main bus feeder breakerfrom the control room, securing power to the bus serving all four pumps.

Most of the components used to trip the circulating water pumps and/or the associatedvalves are safety-grade or equivalent to safety-grade components. This provides added assurance


that the water flow will be secured. These components and related design features are summarizedbelow:

1. All breakers associated with the circulating water pump motor circuits and bus feeder areidentical to seismically qualified, safety-grade breakers.

2. All relays associated with the turbine building level alarms and circulating pump trip circuitsare seismically qualified and safety-grade, and are mounted in the emergency switchgearroom.

3. Trip control relay and alarm relay power is from the vital bus and is redundant.

4. Normal pump controls are identical to seismically qualified and safety-grade controls.

5. Water box inlet and outlet valve controls are mounted on the main control board and areidentical to seismically qualified and safety-grade equipment.

Subsequent to tripping all of the circulating water pumps, the maximum flood elevation inthe affected Turbine Building as a result of a failed CW outlet expansion joint is 256 ft or 1 footbelow the protective watertight barriers.


Tests and inspections are performed periodically.


Control switches are provided in the main control room for the circulating water pumps,condenser water box valves, vacuum priming pumps, and the Class I screen wash pumps.

Local control switches are provided for the bearing lubricating water pumps, screen washpumps, and traveling water screen drives.

The principal alarms provided in the main control room are as follows:

1. Circulating water pump—electrical fault.

2. Lubricating water—low flow.

3. Vacuum priming tank—low vacuum.

4. Traveling water screen—high-level differential.

5. Condenser vacuum breaker valve—valve open.

6. Circulating water pump auto trip—loss of pump.

7. Condenser water box level control—electrical fault.

8. Turbine building sump alarms—high water level.

Local instrumentation is provided where required.


10.4.3 Condensate and Feedwater Systems


See Section 10.1.

The pumps, drives, piping, and 110,000-gallon condensate storage tank of the auxiliaryfeedwater system have all been designed to Seismic Class I criteria (Section 3.2.1). The auxiliaryfeedwater system meets the guidelines of Branch Technical Position ASB No. 10-1. The systemuses a diversity of power sources and redundant equipment and does not rely on any one source ofenergy.

The auxiliary feedwater pumps are designed, fabricated, and tested in accordance withClass III requirements of the Draft ASME Code for Pumps and Valves for Nuclear Power,November 1968. The applicable requirements of the Draft ASME Code for Pumps and Valves(Nov. 1968) are invoked in the design/procurement specification for those pumps.

The turbine-driven auxiliary feedwater pump is rated at 735 gpm and 2806-foot TDH at4200 RPM. The two motor-driven auxiliary feedwater pumps are each rated at 370 gpm and2806-foot TDH. These ratings include recirculation flow. The design is based on the followingconditions:

1. Integrated residual heat release from a full-power equilibrium core.

2. Water inventory of the steam generators operating at normal minimum feedwater level.

3. Minimum allowable steam generator feedwater level permitted to prevent thermal shock orother damage.

4. Automatic starting of auxiliary feedwater pumps to deliver full flow within 1 minute ofsignal.

5. The temperature of the feedwater, supplied from the emergency condensate storage tank, wasassumed to be 35°F when considering thermal shock and 120°F when considering feedwaterenthalpy.

6. The pumps have continuous minimum flow recirculation whenever operating. Pump netratings after recirculation losses are 700 gpm and 350 gpm for the turbine-driven andmotor-driven pumps, respectively.

Design-basis flow requirements for the auxiliary feedwater system are summarized inTable 10.4-1.


The condensate and feedwater systems are shown in Figure 10.4-3, Reference Drawings 4,5, and 7, and Figure 10.4-4. Table 10.4-2 presents design data for the major components of thecondensate and feedwater system.


Condensate is normally withdrawn from the condenser hotwells by two of the threehalf-size motor-driven condensate pumps. The pumps discharge into a common 24-inch headerthat carries the condensate through two parallel steam jet air ejector condensers and through onegland steam condenser.

A condensate recirculation line is provided to return condensate to the condenser at lowturbine-generator loads to provide the minimum required flow of water for the condensate pumps,air ejector condensers, and the gland steam condenser. Downstream of the gland steam condenserand upstream of the chemical feed injection points, flow is passed through the condensatepolishing demineralizer. The common header divides into two 18-inch lines that carry condensatethrough a pair of heater drain coolers and the tube side of two parallel trains of five feedwaterheaters to the suction of three half-size steam generator feed pumps. Two of the steam generatorfeed pumps discharge through two parallel first-point feedwater heaters to a common 26-inchdischarge header for distribution to the steam generators through three 16-inch lines withindividual feedwater flow control valves, positioned by the three-element feedwater controlsystem and through feedwater isolation valves for each steam generator. A remotely operatedsmall bypass valve is provided in parallel with each feedwater flow control valve for manual orautomatic control of feedwater flow to maintain steam generator levels during low-poweroperation or hot shutdown.

Shell-side drains from the four moisture separators are collected in one high-pressurefeedwater heater drain receiver and pumped into the suction of the steam generator feed pumps byone full-size high-pressure feedwater heater drain pump. Drains from the second-point feedwaterheaters are collected in two high-pressure heater drain receivers and pumped into the suction ofthe steam generator feed pumps by individual full-size high-pressure feedwater heater drainpumps.

Chemical feed equipment is provided to ensure proper chemistry control of the secondarysystem during all modes of operation. Secondary system chemical additives include eithermorpholine or ethanolamine for pH control, hydrazine for dissolved oxygen control andammonia, if needed, for further pH control. The primary objective is to minimize the corrosion ofthe steam generators, steam piping, turbines, and condensate and feedwater systems, withsecondary objectives being (1) to prevent or minimize turbine deposits due to carryover from thesteam generator, (2) to minimize sludge deposits in the steam generator, (3) to prevent scaledeposits on the steam generator heat transfer surfaces and in the turbine, (4) to minimizefeedwater oxygen content by the use of hydrazine, and (5) to minimize the potential for theformation of free caustic or acid in the steam generators.

These objectives are met by controlling system chemistry by sampling, including bothcontinuous sampling and laboratory analysis, chemical injection at selected points, continuousblowdown from each steam generator, and chemical protection of the steam generator andfeedwater train internals during outages.


Excessive chloride concentrations and free caustic in combination with other waterconditions are generally considered to be the causes of steam-generator-tube stress corrosioncracking. The Inconel steam generator tubes are not subject to stress corrosion cracking with lowchloride concentrations. The steam generator chlorides are monitored by the analysis of samples.The chloride concentration is kept below the maximum limits recommended by the nuclear steamsupply system (NSSS) vendor by blowdown and condensate polishing.

The concentration of dissolved oxygen and electrolytic conductivity are monitored bycontinuous in-line instrumentation. In each case, the respective concentrations are kept well belowthe maximum limits recommended by the NSSS vendor.

Chemicals for oxygen scavenging and pH control are added to the condensate systemdownstream of the condensate polishing demineralizer. This allows good mixing in thecondensate and feedwater system before the entrance of the feedwater into the steam generator.

Chemicals for oxygen scavenging and pH control can be manually added to the feedwaterand/or the auxiliary feedwater systems, thus allowing the addition of chemicals to the steamgenerators during start-up and shutdown conditions when the condensate system is not flowing.For example, addition to auxiliary feedwater may be required during plant start-up and during wetlayup of the steam generators. Chemical solutions are mixed and stored in tanks on the259-foot elevation of the turbine building. The solutions are pumped from the tanks into theappropriate system by motor-driven, positive-displacement pumps with manually adjustablestrokes. See Figure 10.4-5 and Reference Drawing 6.

Chemicals may be added directly to the steam generators during layup or shutdownconditions through the blowdown system by means of a steam generator transfer pump.Demineralized water may be added directly to the steam generator in this manner, or the contentsof a steam generator may be transferred to another steam generator. There is also provision forpumping the steam generators to the liquid waste system using the steam generator transfer pump.See Reference Drawing 8.

The steam generator wet layup circulation system (Reference Drawing 8) provides forcedcirculation capabilities to the steam generators during wet layup periods. The forced circulationenhances the mixing of oxygen and pH-control chemicals, thus minimizing corrosive attack onthe steam generator components. Circulation is provided by centrifugal pumps rated at 100 gpm at85 feet. The pumps are located in the auxiliary building. The containment isolation valves of thesystem are shown in Table 6.2-39.

The auxiliary feedwater system serves as a backup system for supplying feedwater to thesecondary side of the steam generators at times when the feedwater system is not available,thereby maintaining the heat sink capabilities of the steam generator. As an engineered safeguardssystem, the auxiliary feedwater system is directly relied on to prevent core damage and systemoverpressurization in the event of transients such as a loss of normal feedwater or a secondarysystem pipe rupture and to provide a means for plant cooldown following any plant transient.


Following a reactor trip, decay heat is dissipated by evaporating water in the steamgenerators and venting the generated steam either to the condensers through the steam dump or tothe atmosphere through the steam generator safety valves or the atmospheric steam dump valves.Steam generator water inventory must be maintained at a level sufficient to ensure adequate heattransfer and continuation of the decay heat removal process. The water level is maintained underthese circumstances by the auxiliary feedwater system, which delivers an emergency water supplyto the steam generators. The auxiliary feedwater system must be capable of functioning forextended periods, allowing time either to restore normal feedwater flow or to proceed with anorderly cooldown of the plant to the reactor coolant temperature where the residual heat removalsystem can assume the burden of decay heat removal. The auxiliary feedwater system flow andthe emergency water supply capacity must be sufficient to remove core decay heat, reactor coolantpump heat, and sensible heat during the plant cooldown. The auxiliary feedwater system can alsobe used to maintain the steam generator water levels above the tubes following a loss-of-coolantaccident (LOCA). In the latter function, the water head in the steam generators serves as a barrierto prevent leakage of fission products from the reactor coolant system into the secondary plantshould the LOCA involve a leaky steam generator tube.

Two motor-driven and one steam-turbine-driven auxiliary feedwater pumps supplyfeedwater to the steam generators during a complete loss of offsite electric power, for core heatremoval. Steam to the turbine-driven auxiliary feedwater pump is available through parallelair-operated valves (MS-TV-111A & B and -211A & B). The automatically actuated solenoidvalves for each are powered from redundant dc power sources. In addition, supply valvesMS-TV-111A & B and -211A & B can be manually positioned using selector switches at the maincontrol board or at the auxiliary shutdown panel. MS-TV-111A & B and -211A & B are designedto fail open.

Each motor-driven auxiliary feedwater pump driver is powered from redundant 4.16-kVemergency buses, as described in Section 8.3. Control power for the pump-motor circuit breakersis supplied from redundant batteries.

All three pumps are manifolded into two main headers. Both manifolded headers maysupply any steam generator but are normally aligned so that one manifold carries flow to aparticular generator. A third header provides a flow path from the turbine-driven pump to the “A”steam generator. This third header provides the flexibility required to dedicate a pump to eachsteam generator.

The three auxiliary feedwater headers tie into the main feedwater headers downstream ofthe feedwater containment isolation valves.

Both manifolded headers are provided with either an air-operated valve or a motor-operatedvalve and manual isolation valves at their connections to the auxiliary feedwater headers. Theheader from the turbine-driven pump to the “A” steam generator contains a motor-operated and amanual isolation valve.


The motor-operated valves FW-MOV-100A, B, C, & D, and -200A, B, C, & D receive480V ac power from an emergency bus. These valves are designed to fail in an “as-is” position.

The hand-control valves FW-HCV-100A, B, & C and -200A, B, & C can be remotelycontrolled from the manual station at the main control board or from a similar station at theauxiliary shutdown panel. These hand-control valves and the backpressure-control valvesFW-PCV-159A & B and -259A & B are supplied by seismically designed air lines with individualair storage capacity as discussed in Sections 9.3.1.3.1 through 9.3.1.3.3. The hand-control valvesare designed to fail open.

FW-MOV-100B & D and -200B & D and FW-HCV-100C & -200C are normally open toprovide independent flow paths between each auxiliary feed pump and its respective steamgenerator. All the remaining valves (FW-MOV-100A & C and -200A & C and FW-HCV-100A& B and -200A & B) are normally closed.

Pressure control valves FW-PCV-159A & B and -259A & B control the associated AFWpump FW-P-3A & B discharge header pressure to prevent FW-P-3A or FW-P-3B pump runoutduring the worst case scenario of a main steam line break.

In the normal lineup, flow to the individual steam generators from the auxiliary feed pumpsis controlled from the main control room by remotely operating hand-control valves(FW-HCV-100C & -200C) and two motor-operated valves (FW-MOV-100B & D and -200B& D). Local control is also provided by manual backup valves. Steam to drive the auxiliary feedpump turbine is supplied from the main steam header.

The turbine-driven auxiliary pump is started immediately on a loss of power by opening thesteam valve automatically on a loss of reserve station power or on low-low level in any generatoror on a trip of all main feed pumps. The motor-driven pumps are started automatically on a loss ofreserve station power, low-low level in any steam generator, or a trip of all main feed pumps. Themotor-driven pumps have a delayed start after either a safety injection signal or a simultaneoussafety injection/loss of offsite power signal. These time delays do not impact the pumps’ ability toattain full speed and flow within 60 seconds of these events. These delays are part of the loadsequencing design intended to provide acceptable offsite voltage profiles to meet GDC-17requirements and acceptable EDG transient responses. Section 7.3.1.3.5.3 provides thedescription of AFW auto starts.

10.4.3.3 Design Evaluation

The reactor plant conditions that impose safety-related performance requirements on thedesign of the auxiliary feedwater system are as follows:

1. Loss-of-main-feedwater transient.

a. Loss of main feedwater with offsite power available.

b. Station blackout (i.e., loss of main feedwater without offsite power available).


2. Secondary system pipe ruptures.

a. Feedline rupture.

b. Steam-line rupture.

3. Loss of all ac power.

4. LOCA.

5. Cooldown.

Table 10.4-3 summarizes the criteria used for the above design-basis conditions. Specificassumptions used in the limiting transient analysis (see Section 15.4.2.2) to verify that the designbases are met are shown in Table 10.4-4.

The auxiliary feedwater system has been designed to meet single-failure criteria as definedin Appendix A to 10 CFR 50. Sufficient redundancy has been provided to meet a single activefailure in the short term or a single active or passive failure in the long term. A detailed failureanalysis of the individual components is discussed in Table 10.4-5.

A failure in the feedwater control system could lead to one of two possible events. The firstevent is an abnormal increase of water inventory within a steam generator and the second event isan abnormal decrease of water inventory within a steam generator. An abnormal increase isterminated by the steam generator high-high level function. Two out of 3 level channels at thehigh-high level setpoint in 1 out of 3 steam generators will cause a turbine trip, main feedwaterpump trip, and closure of the main feedwater isolation valves.

An abnormal decrease of water inventory is terminated by the steam generator lowfeedwater flow or low-low water-level functions. Should one of two low-water-level bi-stables inany steam generator indicate an abnormally low water inventory within the steam generator andone-out-of-two flow bi-stables indicate a mass flow mismatch between feedwater input and steamoutput of the steam generator, a reactor and turbine trip will occur. It is conceivable that a slightflow mismatch could develop that lacks the magnitude to trip the mismatch flow bi-stable butwould have a time-integrated value that would reduce the water inventory. In this case, thelow-water-level bi-stables would trip; however, no reactor trip would occur because the flowbi-stables would remain in the untripped state. Thus, the water inventory would be furtherreduced. It should be noted that when a low-water-level bi-stable is tripped, an alarm is actuatedwithin the main control room.

In the event that this trend was not reversed by operator action, two out of threelow-low-water-level bi-stables would indicate a low-low water inventory within any one steamgenerator and would cause the reactor to trip and initiate the start-up of the auxiliary feedwatersystem. The motor-driven auxiliary feedwater pumps will start automatically. The turbine-drivenauxiliary feedwater pump will also start immediately by opening the steam supply valve to the


turbine. Thus, there is no operator action necessary to initiate operation of the auxiliary feedwatersystem (see Figures 7.3-1, 7.3-12 & 10.4-6, and Reference Drawings 13 & 14).

For the case of low-low level in any one, two, or all three steam generators, the amount offeedwater delivered to the steam generators is adjusted by the operator by means of remotelyoperated hand-control valves FW-HCV-100C or -200C or FW-MOV-100B or D or -200B or D, asshown in Reference Drawing 7. The valves are maintained in a normally open position so operatoraction is not a requirement for system functioning.

The operator has the following instrumentation available to properly determine what flowadjustments may be necessary: individual steam generator level indicators, individual auxiliaryfeedwater flow indicators, individual steam generator high-high-level alarms, individual steamgenerator low-level alarms, and individual steam generator low-low-level alarms.

Following any reactor trip, all main feedwater control valves are closed on a low Tavg signal.The low Tavg signal has a setpoint above the no-load temperature. The interlock circuitry used forthis function is redundant. Redundant signals operate redundant solenoid valves that activate theoperator on the feedwater control valve by venting. One of the redundant signals energizes theclosing coils of the motor-operated feedwater isolation valves. These interlocks meet therequirements of IEEE-279. The low Tavg signal is generated with two out of three reactor coolantloops below approximately 554°F.

In conclusion, a single failure within the feedwater control system would not cause anactivation of the emergency core cooling system (ECCS), although it is not a design requirementthat ECCS actuation be prevented for a control system failure in the feedwater system.

The auxiliary feedwater pumps are located outside the containment in the auxiliaryfeedwater pump house, a tornado missile-protected enclosure. They take suction of 35°F to 100°Fwater from a missile-protected, 110,000-gallon emergency condensate storage tank throughindividual pipes. Piping and valves at the storage tank are also protected from missiles. Thecontents of the tank may be recirculated to prevent freezing. In the event further condensate isrequired, it can be supplied by means of gravity from the 300,000-gallon condensate storage tank.Emergency sources of water supply are provided from the fire protection or service watersystems. Pressure transmitters in the suction and discharge piping of the pumps provide indicationof the status of the system on the control board. The analysis presented in Sections 15.2.8.1and 15.2.8.2 shows that two auxiliary feedwater pumps are necessary to maintain a unit in a safecondition following a loss of normal feedwater with offsite power available. However, theauxiliary feedwater pumps are only required to bring the unit to hot shutdown. The twomotor-driven auxiliary feedwater pumps are connected to independent buses of the emergencypower system, as described in Section 8.3.

Operation of the auxiliary feedwater pumps provides residual heat removal for up to 8 hoursusing the emergency condensate storage tank. The turbine-driven pump can be used for residualheat dissipation as long as adequate main steam is available. During normal operation, the turbine


steam supply lines are pressurized to the trip valves in the main steam valve house. The remainingsection at the supply line is supplied with drain collectors with trapped drains to collect thecondensate formed by the introduction of hot steam into the cold pipe. The turbine is asingle-inlet, single-stage, solid rotor unit and any drops of water forming do not damage or impairits operation. When main steam pressure is no longer adequate to operate the turbine-drivenauxiliary feedwater pump, the need for residual heat removal is reduced to a level wherein amotor-driven pump can be used if necessary. In the event that only one pump is available tosupply feedwater following a loss of offsite power, there is adequate capacity to cool down thereactor. The effect of this transient on the overall steam generator fatigue usage factor, asstipulated in Section III of the ASME Code, is that the allowable fatigue usage factor of 1.0 is notto be exceeded. The emergency condensate storage tank is maintained with at least110,000 gallons at all times.

Cooling water to the oil coolers of the auxiliary feedwater pumps is supplied from theindividual pump first-stage leakoff lines with the cooling water returning to the 110,000-gallonemergency condensate storage tank via the minimum recirculation line. Each pump is providedwith a full flow recirculation line to facilitate pump periodic testing in order to verify headcapacity curves. This line is normally isolated by locked closed valves.

The complete loss of redundant ac power sources to the auxiliary feedwater systemcomponents is highly improbable. The redundancy of onsite ac power supplied from the dieselgenerators, along with redundancy of offsite ac power supplied from the switchyard, ensures thatat least one source of ac power will be available.

Notwithstanding, the auxiliary feedwater system can be operated independently of acpower. MOV-FW-100B and D and HCV-FW-100C are the valves used to control flow to the steamgenerators. These valves are open when the system is put into operation. If ac power wereunavailable, manual backup valves would be used to decrease flow into the steam generators bymanually throttling the valves. The capacity of the turbine-driven feedwater pump is such that itwould not cause the steam generator, to which it is aligned, to fill in the 30 minutes conservativelyassumed for operator action.

In the event of a feedwater line break downstream of the check valve and the single failure(in the closed position) of the backpressure control valve or a motor-operated discharge valve, orthe failure of an auxiliary feedwater pump aligned to one intact steam generator, the remainingintact steam generator will be supplied with adequate flow from its respective supply line andauxiliary feedwater pump. Flow to the unaffected steam generator and flow out the broken linewill result in a loss of approximately one third of the condensate storage tank inventory during thefirst 30 minutes after the pipe break. At that time, it is conservatively assumed that operator actiontakes place to isolate flow out the broken line to prevent excessive drawing down of thecondensate storage tank.


In the event of a pipe rupture in the steam supply line to the turbine-driven auxiliaryfeedwater pump and the single failure of any valve in the discharge line of the other two pumps, orthe single failure of one of the two pumps, one auxiliary feedwater pump (providing adequateflow to one steam generator) would still be available.

10.4.3.3.1 Potential for Water Hammer in Steam Generator Feedlines

The installation of J-tubes to the steam generator feedwater sparger ring precludes thewater-hammer mechanism, which has been identified as water-steam slugging occurring as aresult of a steam bubble collapse. The J-tubes prevent rapid draining of the feedwater sparger andadjacent feedwater piping. On the initiation of auxiliary feedwater flow, they serve to ensure thatthe sparger ring is filled prior to recovery and act as a large positive vent for any trapped steambubble.

All steam generator orifice holes on the bottom side of the sparger have been plugged, andJ-tubes installed on the upper side. This has been done to avoid water-hammer events caused bysteam bubble collapse following the initiation of auxiliary feedwater flow to recover the feedwatersparger ring.

Extensive in-plant tests conducted at Trojan and Indian Point Unit 2 have shown that thefeedwater hammer experience has been effectively precluded by the J-tube modification and thatno operating restrictions on auxiliary feedwater flow are necessary to ensure the safe operation ofthe plant.

Since the occurrence of water hammer has been precluded, there is no need to considereither the stress effects or the resulting loads to the system piping supports or equipment design.

Stone & Webster has developed two major computer programs, WATHAM (for waterhammer) and STEHAM (for steam hammer), for developing forcing functions due toflow-induced transients.

WATHAM is a general-purpose computer program used for developing time-dependentforcing functions required in the water-hammer analysis of characteristics with finite differenceapproximations for one-dimensional homogeneous fluid flows. The time-dependent initial andboundary conditions of piping components, which include valves and pumps, influence the fluidmotion. Also, the effect of pipe friction, vapor collapse, and entrapped air has been considered.

STEHAM is a general-purpose computer program used for developing time-dependentforcing functions required in the steam-hammer analysis of piping systems. This program hasbeen developed and is based on the method of characteristics with finite differenceapproximations for one-dimensional homogeneous fluid flows. It is also dependent on pipingcomponent characteristics with the allowance of pipe friction and heat transfer forone-dimensional steam flow. Influences of flow control valves, steam reservoirs, and pipeconnections on the behavior of flow response are studied in detail.


The following systems have been analyzed for steam-hammer and water-hammeroccasional mechanical loadings:

1. Feedwater.

2. Main steam and main steam bypass.

3. Pressurizer safety/relief.

4. Moisture separator crossover.

5. Quench and recirculation spray.

6. Service water.

These systems analyzed for water hammer and steam hammer have been selected on thebasis of past experience in the power industry (Industrial Accident Report) and on the basis ofcomponent characteristics for North Anna Unit 1 and 2 systems that generate significantflow-induced forcing functions.

First, the flow-induced, time-dependent forcing functions are developed based on the pipingsystem characteristics and the time-dependent initial and boundary conditions of the components(pumps, valves, etc.).

These time-dependent forcing functions are then applied to the applicable piping system inorder to perform time-history dynamic analysis on these systems. The calculated occasionalmechanical loading stresses are then combined with other primary stresses and held within pipingallowables with the use of pipe supports and restraints. Peak occasional mechanical loadingstresses are combined with peak seismic stresses by the square root of the sum of the squaresmethod, and the combination is then added to other primary loading stresses absolutely.

Testing was performed on Units 1 and 2 to demonstrate that the occurrence of waterhammer associated with recovering the steam generator feedwater sparger ring was precluded byJ-tube installation and feedwater loop seal arrangement. The test procedure added auxiliaryfeedwater to the steam generators with the water level below the sparger ring and observed theresponse of the system. The test conditions were points representative of the full range ofoperating and accident conditions, that is, no load, 100% power, and reduced pressure (accident)conditions. Accelerometers were mounted on feedwater piping in proximity to the steamgenerators to detect water and auxiliary feedwater pressure during sparger recovery.


Testing of the auxiliary feedwater system is conducted in accordance with TechnicalSpecifications.



The principal controls of the condensate and feedwater systems are located in the maincontrol room.

In addition, an auxiliary shutdown panel in the emergency switchgear room providescontrol for the auxiliary feedwater system.

The turbine-driven feedwater pump has, as part of its controls, a locally mounted throttletrip valve. In order to increase the control room operator’s awareness of auxiliary feedwatersystem availability, an alarm will notify the control room operator whenever the throttle trip valveis in the trip position, as could be done locally with the overspeed trip lever. The alarm has beenadded via a position switch on the throttle trip valve wired to the main control board annunciator.

To further increase the control room operator’s awareness of auxiliary feedwater systemavailability, the turbine-driven feedwater pump lube oil reservoir level will be monitored. Analarm will notify the control room operator whenever a low lube oil level condition occurs. Thisalarm is wired in parallel to the throttle trip valve position alarm and utilizes the common alarmpoint on the main control board annunciator.

An alarm will notify the control room operator when either of the auxiliary feedwatersystem discharge motor-operated valves and hand-control valves is out of its normal position, andwhen either auxiliary feedwater system discharge pressure-control valve is closed after theassociated motor-driven pump has started. This will be accomplished by control roomannunciation from limit switch contacts of each of the above-mentioned auxiliary feedwatersystem discharge valves. Annunciating for closed position after pump start-up for eachpressure-control valve will be delayed for 20 seconds by the addition of a timing relay to allowsufficient time for the valves to open after the pump has started.

Redundant safety-grade level indication and low-level alarm capability have been installedin the main control room for the auxiliary feedwater system emergency condensate storage tank(1-CN-TK-1). Both level loops are composed of seismically and environmentally qualifiedtransmitters, with power supply from safety-related Class 1E vital buses. One safety-grade alarmindicator is on each loop, set to alarm at 20 minutes of water level left in the tank for thehighest-volume auxiliary feed pump operation.

Each indicator will relay the input to a common annunciator window, which will alarm atthe same setpoint.

10.4.4 Main Condenser


The condensers are designed in accordance with the Heat Exchange Institute standards forsteam surface condensers.


The design parameters for each condenser are as follows:

Steam condensed 7,096,000 lb/hr

Circulating water 940,300 gpm

Surface 618,000 ft2

Number of tubes 53,856

Tube material SS 304

Tube outside diameter 1 in.

Effective length 43 ft. 10 in.

Backpressure 3.5 in. Hg

Temperature 120°F


The condenser is a conventional, two-shell, single-pass unit with divided water boxes. Thecondenser is supported from the basement floor of the turbine building and is provided with arubber belt-type expansion joint at the turbine exhaust connections. Steam and condensateequalizing lines are provided between the condenser shells. Half-size fifth- and sixth-point heatersare mounted in each condenser neck.

For initial condenser shell-side air removal, a noncondensing priming ejector is provided foreach shell. These ejectors function by using steam from the auxiliary steam system(Section 10.4.1).

Two twin-element, two-stage, steam jet air ejector units, each complete with inter- andafter-condensers, are provided for removing noncondensible gases from the condenser shellsduring normal operation. For normal air removal, one element of each ejector unit is operated percondenser shell. The ejectors function by using auxiliary steam and normally discharge to theventilation vent. The air ejector discharge is diverted to the reactor containment on highradioactivity in the discharge.

The condenser air removal equipment is discussed in more detail in Section 10.4.6.

The condenser hotwell normally contains 71,000 gallons of condensate. Provisions havebeen made for detecting circulating water inleakage by sampling condensate at the condensatepump discharge.

The condenser tubes are continuously cleaned on-line by an Amertap tube cleaning systemcomplete with controls, piping, reinjection and recirculation pumps, collector, and sponge rubberballs.



The condenser hotwell is of the deaerating type capable of reducing the oxygen content ofthe condensate to less than 0.005 ppm. The deaerating capability is necessary as there is nodeaerating feedwater heater in the feedwater cycle.


During preoperational testing, unit trips are simulated to check the ability of the condenserto handle the maximum bypass steam dump flow as discussed in Section 10.3.1.


The condenser tube cleaning equipment is designed to operate in automatic or manualmode. Once it is put into operation, the equipment can be operated either locally (automatic ormanual) or from the main control room (automatic only). Local or MCR operation is determinedby a control transfer switch on the system mimic control panel located in the turbine buildingbasement.

Condenser hotwell level is monitored both locally and in the main control room.

Alarms are provided in the main control room for condenser tube cleaning equipmenttrouble and condenser hotwell high and low levels.

Local instrumentation is provided as required.

10.4.5 Lubricating Oil System


See Section 10.1.

All piping is designed in accordance with the ASME Code for Pressure Piping,ANSI B31.1-1967.


The lubricating oil system, shown in Figure 10.4-7 and Reference Drawing 9, is provided toperform the following functions:

1. Store lubricating oil.

2. Supply oil to and receive oil from the turbine-generator oil reservoir.

3. Purify a side stream of oil from the turbine-generator oil reservoir on a continuous bypassbasis.

4. Clean and reclaim used oil from the storage tanks, pumping it from the “used oil” storagetank via the conditioner to the “clean oil” storage tank.


The lubricating oil system consists of a 10,000-gallon turbine oil reservoir, two16,000-gallon storage tanks, a lube-oil conditioner, a combination fill/batch cleaning pump, and acombination circulating/drain pump. The combination fill/batch cleaning pump and the two16,000-gallon storage tanks are common to both units.

The combination fill/batch cleaning pump is a two-speed pump that is operated at its higherspeed for draining purposes and at its lower speed for circulating the lube-oil through the system.

The pumps and piping are arranged so that oil can be processed from the oil reservoir oreither of the two storage tanks. The process oil can be returned to the oil reservoir or to either ofthe storage tanks.

The two 16,000-gallon storage tanks are normally designated “clean” and “used,” but areinterchangeable.

A lubricating oil purifier is provided to supplement the turbine lube-oil conditioner.

The turbine lube-oil reservoir is the source of lubricating oil for the turbine generator.


The pumps and piping are arranged so that oil can be processed from the oil reservoir oreither of the two storage tanks. The process oil can be returned to the oil reservoir or to either ofthe storage tanks.

The lube-oil tanks and lube-oil fill pump are located in a fireproof room equipped with afire-protection sprinkler system (Section 9.5.1), and vent fans.

The lube-oil reservoir, lube-oil conditioner, and lube-oil circulating pumps are alsoprotected by a sprinkler system.

The lube-oil conditioner is surrounded by a sump to accommodate a loss of oil in case of arupture of the conditioner.

Vapor extractors purge oil fumes from the oil conditioner and reservoir and exhaust to theatmosphere outside the turbine building.


The lube-oil piping is hydrostatically tested before initial operation. Other tests andinspections are performed on a periodic basis.


Control switches for the lube-oil circulating and lube-oil fill pumps are local only.

An alarm is provided in the main control room for low level in the lube-oil conditioner.



10.4.6 Secondary Vent and Drain Systems


See Section 10.1.

Because the steam and power conversion system is normally nonradioactive, vents anddrains are arranged in much the same manner as those in a fossil-fueled power station. However,because air ejector vents and steam generator blowdown can possibly become contaminated andbecause they discharge to the environment, they are monitored and discharged under controlledconditions.

All piping penetrating the containment is designed in accordance with the Code for NuclearPower Piping, ANSI B31.7-1969, up to and including the containment isolation valves.

All other piping is designed to the Code for Pressure Power Piping, ANSI B31.1-1967.


Vents from the turbine generator, which handle carbon dioxide, hydrogen, oil vapor, andother nonradioactive gases, are discharged directly to the atmosphere outside the turbine building.

Generally, secondary plant piping drains to the condenser.

The condenser air ejector vent is shown in Reference Drawing 1.

There are two priming ejectors and two twin-element, two-stage steam jet air ejectorsserving both main condensers. The priming ejectors are used to evacuate large air quantities fromthe condensers during start-up. The two-stage steam jet air ejectors are used during normaloperation to remove accumulated noncondensibles from the condensers.

The priming ejectors take suction from the air suction headers leading from the condensersand discharge to the atmosphere.

The twin-element, two-stage steam jet air ejectors take suction from the air suction headersleading from the condensers and discharge to the atmosphere, but the discharge is diverted to thereactor containment if the radiation monitoring system (Section 11.4) detects radioactivity in thedischarge stream. The air ejector vapors and motive steam are condensed by condensate beingcirculated through the tube side of the inter- and after-condensers of the air ejectors. A loop sealautomatically drains the intercondenser back to the main condenser. The after-condensers drain tothe turbine building sump through a loop seal.

If a steam generator tube leak develops with subsequent contamination of the steam, theradioactive noncondensible gases would be detected by the radiation monitor located in the airejector discharge line. When the radioactivity level reaches the setpoint of the monitor, trip valves


in the air ejector discharge lines will automatically divert the discharge to the reactor containment.Details of the radiological evaluation for normal operation are discussed in Chapter 11.

Each steam jet air ejector is designed to remove 25 cfm of free air at 1 inch Hg abs whensupplied with 1600 lb/hr of saturated steam at 140 psig. During normal operation, it is anticipatedthat 12.5 scfm of air and 41.5 lb/hr of steam per unit will be released to the atmosphere and that1800 lb/hr of condensate will be drained to the turbine building sump.

Each steam generator is provided with blowdown connections for the control of the ionicimpurity concentrations on the shell (secondary) side of the steam generator. The steam generatorblowdown system is shown in Figure 10.4-8 and Reference Drawing 10.

Each blowdown line contains three normally open trip valves, two inside the containmentand one outside. The steam generator blowdown system is divided into two parallel systems.Either can be isolated from the other or both can be operated simultaneously.

The first of these systems is the high-capacity steam generator blowdown system. Thissystem is normally aligned to receive blowdown. The rate of blowdown is controlled by flowcontrol valves and uses blowdown flash tank BD-TK-2. The normal blowdown rate for thehigh-capacity blowdown system is approximately 90,000 lb/hr with a system design rate of100,000 lb/hr. The design of this system allows for heat recovery by two means: (1) by use of aflash tank that returns steam to the third-point feedwater heaters, and (2) by use of a flash tankdrains cooler that transfers heat from the drains to the main condensate system.

During steam generator blowdown, the liquid passes to the flash tank, where the steam isdrawn off to the third-point feedwater heaters, and the liquid is drained to the blowdown flash tankdrain cooler, then discharged to the circulating water discharge tunnel. A continuous radiationmonitor and a sampling line for manual grab sampling are located in the cooled flash tank drainline upstream of their point of discharge to the circulating water discharge tunnel.

A pair of pressure-control valves on the flash tank vent line keep a minimum backpressureon the tank to limit the amount of flashing during reduced load operation.

The blowdown from each steam generator is individually monitored for radioactivity asdescribed in Section 11.4. If the radiation monitor detects contamination exceeding a set limit inthe blowdown sample, an alarm is initiated in the main control room. Details of the radiologicalevaluation are discussed in Chapter 11. The radiation monitor in the high-capacity blowdownsystem effluent line does not perform a safety function, but is included in the design for addedprotection against release of radiation to the environment.

The high-capacity blowdown system is automatically terminated, after a short time delay toprevent spurious trips, for any of the following abnormal conditions:

1. High-high flash tank level

2. Low-low flash tank level


3. High flash tank pressure

4. High condenser pressure (no time delay)

5. High effluent discharge radiation

6. High-high drains cooler outlet temperature

7. Low-low inlet flow (2 out of 3 trip matrix)

8. High-high inlet flow

9. High-high discharge flow

10. Loss of power to either the control cabinet or radiation monitor

The high-capacity blowdown system has an automatic feature that trips the pressure controlvalve (BD-PCV-100) should either extraction steam non-return valve trip closed (ES-NRV-103A,ES-NRV-103B). The non-return valves are tripped closed on high-high feedwater heater level andturbine trip. This action will close BD-PCV-100 and the blowdown flash tank pressure will becontrolled by BD-PCV-101 which diverts steam to the condenser. The high-capacity steamgenerator blowdown system is isolated automatically on a containment isolation signal.

The second steam generator blowdown system is the low-capacity blowdown system, inwhich the rate of blowdown is manually regulated by hand-control valves, and uses blowdowntank BD-TK-1. This system is a backup to the high-capacity steam generator blowdown system.

When the low-capacity blowdown system is in operation, blowdown from any or all of thethree steam generators passes to and flashes in the blowdown tank. The blowdown tank isequipped with a vent condenser that condenses vapor discharge from the tank. Condensate fromthe blowdown tank and vent condenser is drained to the liquid waste disposal system(Section 11.2). Noncondensibles are vented to the atmosphere.

Using the low-capacity system, the three steam generators can blow down normally10,900 lb/hr, to a maximum of approximately 40,000 lb/hr, of water to the blowdown tank andsubsequently to the liquid waste disposal system.

The low-capacity steam generator blowdown system is isolated automatically on acontainment isolation signal.


Loss of power or air causes the trip valve in the air ejector line to the ventilation vent to failclosed, thus preventing possible radioactive contaminants in the condenser steam space fromreaching the atmosphere. In addition, the air-operated shutoff valve in the steam supply lines tothe air ejectors also fails closed on a loss of power or air.

The trip valves leading to the containment are part of the containment isolation system(Section 6.2.4). A containment isolation signal will over-ride any other signal the valves receive.


Loss of power or air will cause the three blowdown trip valves for each steam generator tofail closed. Two of these valves are part of the containment isolation system (Section 6.2.4) andwill also close automatically on an auxiliary feedwater pump auto start signal (Section 10.4.3), orby AMSAC activation. The two valves inside containment close automatically in the event ofexcess flow, as described in Section 3C.5.4.6.2.1.


Vent and drain lines are hydrostatically tested before initial operation.

Valves that are part of the containment isolation system are tested in accordance withTechnical Specifications.


Push buttons are provided in the main control room for opening and closing the controlvalves admitting steam to the air ejectors. Push buttons are also provided for opening and closingthe containment isolation blowdown trip valves.

An air leakage meter is provided with each main condenser air ejector to make checks ofsystem air leakage during normal operation.

The position of the trip valves that open the air ejector discharge to the containment isindicated in the main control room.

Alarms are provided in the main control room for high radioactivity in the air ejector airdischarge and steam generator blowdown.

The steam generator blowdown system includes two containment isolation trip valves persteam generator. Containment isolation trip valves TV-BD-100A, B, C, D, E, and F are normallyopen and fail closed on a loss of air or loss of electrical power to the associated solenoid valve. Aflow switch contact in the control circuitry for trip valves TV-BD-100B, D, F, G, H, and J ispresent for the intended functioning of isolating a high-flow condition caused by possibledownstream pipe break. Circuitry has been installed to prevent high-flow trips on the steamgenerator blowdown lines during initial pressurization of the steam generator. The flow switchtrip signal is blocked during the initial pressurization of the blow-down lines. Once pressurized,the blocking signal will automatically be cleared and thus will not defeat the intended function ofthe high-flow trip for downstream pipe breaks.

10.4.7 Bearing Cooling Water System


See Section 10.1.

The turbine plant equipment is designed for full-load operation with bearing cooling watersupplied at a maximum temperature of 95°F.


All piping is designed in accordance with the ASME Code for Pressure Piping,ANSI B31.1-1967 except effective March 2005, non-metallic chemical addition piping isdesigned in accordance with ASME B31.3, 2002 Edition, Process Piping.


The bearing cooling water system is shown schematically in Figure 10.4-9 and ReferenceDrawings 11 and 12. Table 10.4-6 presents design data for the major system components. Thebearing cooling water system supplies cooling water to the steam and power conversion systemequipment. The bearing cooling water system is normally a closed-loop cooling system that usesan induced-draft cooling tower. The cooling tower consists of four cells (two cells for each unit),which are erected over a common cold-water basin. Provision has been made in the system toswitch operation from the cooling tower to Lake Anna as discussed below.

With the cooling tower placed in service, the bearing cooling water pumps take suctionthrough a header common to both units from the cooling tower’s cold-water basin, and dischargethrough fine mesh self-cleaning strainers before circulating through the equipment and returningto the cooling tower via a header common to both units. The system is also provided with achemical addition system and sample points for corrosion control.

As an alternate cooling source when the cooling tower is not in service, the bearing coolingwater pumps take suction from the circulating water intake tunnel in the turbine building anddischarge through fine mesh self-cleaning strainers before circulating through the equipment anddischarging to the circulating water discharge tunnel.

Two 100%-capacity mechanical chiller condenser pumps are installed in parallel with theUnit 2 bearing cooling water pumps and associated system components. This arrangementpermits the mechanical chiller condenser pumps to take suction from and discharge back to thesame source as the bearing cooling water pumps. The mechanical chiller condenser pumps aredesigned to supply cooling water to the condenser of the mechanical chilled water unit describedin Section 9.2.2 (see Figure 10.4-9 and Reference Drawing 11).

The principal equipment served by the bearing cooling water is as follows:

EquipmentDesign Flow

(gpm)

Generator hydrogen coolers 4500

Hydrogen seal-oil coolers 360

Turbine oil coolers 2934

Exciter cooler 300

Isolated phase bus duct air coolers 276 (U1)130 (U2)

Sample coolers 50


As an alternate source of cooling water, the chilled water subsystem can supply the Unit 1isolated phase bus duct cooler. The flash evaporator is obsolete and no longer used. The bearingcooling makeup line between Units 1 and 2 that used to provide makeup water to the flashevaporator has been removed from service. The cooling water flowing through the majorequipment coolers, such as the hydrogen and air coolers, is controlled automatically to maintainconstant temperature of the cooled fluid.


To provide operational flexibility and system reliability, provision has been made to transfersystem operation from the cooling tower to Lake Anna (via the intake and discharge tunnels).Each unit is also provided with two full-size bearing cooling water pumps, cooling tower makeuppumps, and self- cleaning strainers to increase system reliability. Normally, only one set of pumpsand strainers would be operating, with the remaining pumps and strainers for backup service.

Units 1 and 2 share a common suction line and return between the cooling tower and thebearing cooling water pumps.

A loss of bearing cooling water would require a unit shutdown.

Condensate, feed, and heater drain pumps 300

Flash evaporator (during unit shutdown)(not used)

9280

Central station air conditioner (Unit 1 only) 710

Chiller condenser 4000

Chiller condenser air ejector 100

HP fluid reservoir oil coolers 20

Vacuum priming pumps 45

Mechanical chiller (Unit 2 only) 1500

Mechanical chiller - Unit 1 (SG on-line chemistry) 42

Mechanical chiller - Unit 2 (SG on-line chemistry) 25 each, quantity of 2

Primary sample coolers (6/unit) (SG on-line chemistry) 7 each

Primary sample coolers (6/unit) (SG on-line chemistry) 12 each

Main generator breaker (Unit 1 only) 50

EquipmentDesign Flow

(gpm)



All piping is hydrostatically tested before initial operation. The usage of the system duringplant operation provides a continuing check of system functionality status; specific periodictesting is not required.


Control switches from the bearing cooling water pumps, cooling tower makeup pumps, andcooling tower fan motors are provided in the main control room. Control switches are alsoprovided in the main control room for the cooling tower bypass line valves, the circulating watertunnel isolation valves, and the cooling tower isolation valves. Local control switches areprovided for the bearing cooling water self-cleaning strainers.

The principal alarms provided in the main control room are as follows:

1. Bearing cooling water pumps low discharge pressure.

2. Bearing cooling water pumps low suction pressure.

3. Bearing cooling water pump auto trip/system misaligned.

4. Cooling tower makeup pump low discharge pressure.

5. Mechanical chiller condenser pump low discharge pressure (Unit 2).

6. Loss of power to cooling tower fan motor.

7. Cooling tower basin high/low temperature.

8. Cooling tower basin high/low water level.

9. High cooling tower fan vibration.


10.4.8 Condensate Polishing System—Powdered-Resin Type

The function of the condensate polishing system is to remove impurities from thecondensate stream that result from condenser tube leakage and to produce a high-quality effluentwithin the feedwater and steam generator chemistry specifications. The condensate polishingsystem is shown in Reference Drawing 5.


The design bases of the condensate polishing system are the following:

1. The system, in conjunction with continuous steam generator blowdown, shall maintain thecondensate water chemistry in accordance with the requirements of the NSSS vendor.


2. Sufficient demineralizer redundancy shall be provided to allow demineralizer precoatingwhile the system retains its normal polishing capacity.

3. The system shall be sized to accommodate 100% condensate flow.


The condensate polishing system consists of five powdered-resin filter demineralizers in thecondensate stream between the gland steam condenser and the chemical feed injection point. Thesystem is capable of polishing the full condensate flow while one of the demineralizers is beingbackwashed and precoated or is on standby. Anion resin is operated in the hydroxide cycle andcation resin is operated in the ammonia, hydrogen morpholine, or ethanolamine cycle. Thecation/anion resin ratio can be varied over a wide range, with various mixtures determined bycondensate chemistry. Each vessel contains approximately 350 lb of resin. The demineralizerdesign includes the provision for operation of the vessels without a resin precoat, during whichtime they function as a mechanical filter. Each of the five 6-foot-diameter cylindrical vertical filterdemineralizers has a flanged removable head that allows internal assemblies to be easily removedif required. Each vessel contains filter elements sized to hold the resin. The 60- to 400-meshion-exchange resin is used as a thin precoat (1/16-inch to 1/2-inch thick) on the filter elements.The vessels’ hold pump will automatically start in the event that flow falls below that required toretain the resin coat on the filter element. Powdered resin in this system is disposed of after itscapacity is expended. When a vessel needs new resin, the exhausted filter demineralizer is isolatedand a combination of condensate and air is admitted to remove the resin by backwashing. Thebackwash slurry is transferred to the backwash recovery tanks for separation and settling. Air usedin the backwash operation is filtered by HEPA filters before being discharged. Each backwashwill require up to 15,000 gallons of condensate.

New resin, which is received fully regenerated by the manufacturer, is placed in the precoattank along with condensate quality water. The resin is mixed in the condensate water using anagitator to form a slurry. The slurry is then pumped by the precoat pumps through the previouslybackwashed demineralizer until the filter elements are completely coated.

The expended resin in the backwash recovery tanks is transferred to the phase separator forfurther settling before being drained by gravity flow for waste resin disposal. Excess water isreturned to the backwash recovery tanks. When another filter demineralizer vessel requires a newprecoat, the water contained in the backwash recovery tank can be pumped through the vesselrequiring the precoat.

All piping is constructed to ANSI B31.1-1967. Pressure vessels are fabricated, inspected,tested, and stamped in accordance with the ASME Code, Section VIII, Division 1, 1974.

Radioactivity would be concentrated in the condensate polishing system only if primary tosecondary leakage occurs in a steam generator.


10.4.8.3 Safety Evaluation

Normally, condensate polishing will be used to control inleakage during short periods oftime or until the inleakage can be repaired.

In the event of high primary to secondary leakage, the vessels can be backwashed should theradiation level reach an unacceptable value. The resin can be sent to the liquid waste system forsolidification and disposal with other wastes (See Section 11.2.3).


The condensate polishing system can be in continuous operation whenever the condensatesystem is operating. Even with no condenser inleakage, each filter demineralizer may beprecoated and backwashed periodically, if required by system chemistry. The conductivity of thecondensate leaving the condenser hotwells is monitored continuously during plant operation, thusproviding a method of evaluating system performance and determining the need for resinreplacement.


The condensate polishing control panel contains two redundant programmable logiccontrollers (PLC), power supplies, communication modules, and operator interface units (CRTbased). This redundancy results in a high level of system reliability and flexibility.

The PLC performs the automatic control functions and modulation of control variables forthe CP System. Display of equipment status, indications of process variables, and alarm status isprovided on the CRT. All of the operator actions are initiated through programmable functionkeys, the keyboard, or icon type graphical symbols.

The conductivity of the effluent condensate from any of the five Powdex Vessels ismonitored by the PLC when a resin precoat is present. Each of the vessel sample lines containstwo conductivity probes and a cation chamber. The conductivity measurements from the vesseland cation chamber discharge are monitored by the PLC and will provide an alarm on highconductivity.

A differential pressure transmitter is provided to monitor the differential pressure acrosseach filter demineralizer and a differential pressure transmitter is provided for the entirecondensate polishing system. A trouble alarm signal is provided at the main control board. A highdifferential pressure alarm is logged on the CRT screen. The polishing system will automaticallybe bypassed on high system differential pressure.

All system alarms are provided and indicated on the CRT screen at the local control panel towarn operators of faulty and/or out of specification system parameters. In turn, a general troublealarm is provided at the main control board to notify operators to investigate system operatingconditions.





1. 11715-FM-072A Flow/Valve Operating Numbers Diagram: Auxiliary Steam and Air Removal System, Unit 1

12050-FM-072A Flow/Valve Operating Numbers Diagram: Auxiliary Steam and Air Removal System, Unit 2

2. 11715-FM-16B Flow Diagram: Auxiliary Steam, Primary Plant

3. 11715-FM-077A Flow/Valve Operating Numbers Diagram: Circulating Water System, Unit 1

12050-FM-077A Flow/Valve Operating Numbers Diagram: Circulating Water System, Unit 2

4. 11715-FM-17A Flow Diagram: Condensate

12050-FM-17A Flow Diagram: Condensate

5. 11715-FM-17B Flow Diagram: Condensate Polishing Demineralizer

12050-FM-17B Flow Diagram: Condensate Polishing Demineralizer

6. 11715-FM-102A Flow/Valve Operating Numbers Diagram: Chemical Feed Systems, Unit 1

12050-FM-102A Flow/Valve Operating Numbers Diagram: Chemical Feed Systems, Unit 2

7. 11715-FM-074A Flow/Valve Operating Numbers Diagram: Feedwater System, Unit 1

13075-FM-102C Flow/Valve Operating Numbers Diagram: Chemical Feed System, Unit 1

12050-FM-074A Flow/Valve Operating Numbers Diagram: Feedwater System, Unit 2

8. 11715-FM-102B Flow/Valve Operating Numbers Diagram: Chemical Feed Systems, Unit 1

12050-FM-102A Flow/Valve Operating Numbers Diagram: Chemical Feed Systems, Unit 2


9. 11715-FM-083A Flow/Valve Operating Numbers Diagram: Lube Oil Lines, Unit 1

10. 11715-FM-098A Flow/Valve Operating Numbers Diagram: Steam Generator Blowdown System, Unit 1

12050-FM-098A Flow/Valve Operating Numbers Diagram: Steam Generator Blowdown System, Unit 2

11. 11715-FM-24A Flow Diagram: Bearing Cooling Water

12050-FM-24A Flow Diagram: Bearing Cooling Water

12. 11715-FM-24B Flow Diagram: Bearing Cooling Water

13. 11715-LSK-5-13B Turbine Driven, Steam Generator, Auxiliary Feedwater Pumps

12050-LSK-5-13B Turbine Driven, Steam Generator, Auxiliary Feedwater Pumps

14. 11715-LSK-5-13C Auxiliary Feedwater Control Valves

12050-LSK-5-13C Auxiliary Feedwater Control Valves



Table 10.4-1AUXILIARY FEEDWATER SYSTEM DESIGN BASIS

AFW Pump Mark Number

Design Basis Delivered Flow toS/G Required by Accident Analysis

(gpm) Comments

1/2-FW-P-2 400 Turbine Driven AFW Pumps

1/2-FW-P-3A, 3B 300 Motor Driven AFW Pumps

Note: The main feedline break analysis requires a minimum auxiliary feedwater flow of 300 gpm delivered to an intact steam generator at the steam generator safety valve setpoint (with allowance for uncertainties). See Section 15.4.2.2. The turbine driven AFW pump minimum required flow, 400 gpm, exceeds the required flow for the main feedline break analysis and provides adequate flow for analyses which assume the motor driven AFW pumps are unavailable. The AFW system minimum delivered flow calculation determines the minimum delivered AFW flow for each AFW pump, with mini-flow recirculation and oil cooler flows included, to its respective steam generator at the minimum MSSV setpoint pressure plus uncertainty and presents resulting flow margins over minimum required accident analysis flows.


Table 10.4-2DESIGN DATA FOR MAJOR COMPONENTS

OF CONDENSATE AND FEEDWATER SYSTEMS

Surface condenser (CN-SC-1A and B)

Duty (total) 6,594,900,000 Btu/hr

Tube side design pressure 20 psig

Shell and tube support plates ASTM A285-C

Tube sheets 304 stainless steel

Tubes 304 stainless steel

Shell material ASTM A285-C

Shell design pressure 15 psig to full vacuum

Shell design temperature 250°F

Air ejector after/intercondenser (CN-EJ-1A and B)

Duty 3,208,697 Btu/hr

Tube side design pressure 700 psig

Steam chest material ASTM-A285-C

Shell material ASTM-A285-C

Tube material 304 stainless steel



Condensate pumps (CN-P-1A, B, and C)

Capacity (each) 8500 gpm (1 backup)

Design pressure 550 psig (casing)

Casing material ASTM A48

Impeller material ASTM B143


Head 1230 ft

Condensate storage tank (1-CN-TK-2)

Capacity 300,000 gal


Design pressure atmospheric

Shell material ASTM-A285

Head material ASTM-A285-C

Bottom plate ASTM-A285-C


Condensate storage tank (1-CN-TK-1)

Maximum Capacity 119,568 gal

Normal Operating Capacity 110,000 gal


Design pressure atmospheric

Shell material ASTM A285-C

Head material ASTM-A285-C

Bottom plate ASTM-A285-C

Tank is missile protected by surrounding concrete structure

Gland steam condenser (1 & 2 CN-SC-2)

Duty (each) 4,221,821 Btu/hr

Tube design pressure 700 psig

Tube design temperature 650°F

Tube 304 SS, 28 fins/inch

Tube plates, tube support plates, shell, and water box

carbon steel

Shell design pressure 14 psig


Flash evaporator makeup pumps (1-WT-P-12A,B; 2-WT-P-12A) (NOT USED)

Capacity 340 gpm

Design temperature (casing) 35-95°F

Design pressure (casing) 100 psig

Head 60 ft

Casing material cast iron

Impeller bronze

Second-point heater drain receiver (1 & 2 SD-TK-2A, B)

Capacity 400 ft3



Shell material ASTM A516-70

Head material ASTM A516-70

Table 10.4-2 (continued) DESIGN DATA FOR MAJOR COMPONENTS



Flash evaporator (condenser section) (NOT USED)

Duty 61.6 × 106 Btu/hr



Tube design pressure 700 psig

Tube design temperature 410°F

Shell material carbon steel

Tube material 304 stainless steel

Tube sheet material carbon steel

Flash evaporator recycle pumps (1,2-WT-P-2A, B) (Unit 1 abandoned in place)

Capacity 5800 gpm



Head 55 ft

Casing material cast iron

Impeller bronze

Flash evaporator distillate pumps (1,2-WT-P-1A, B)

Capacity 465 gpm

Design temperature (casing) 165°F


Head (NAS-39) 240 ft

Casing material 316 stainless steel

Impeller 316 stainless steel

Steam generator feed pumps (FW-P-1A, B, C)

Capacity (1 backup) 16,250 gpm

Head 1980 ft



Casing material ASTM CA-6NM 13-4 chrome

Impeller (11-13 chrome) ASTM A296-CA15




First-point heater (FW-E-1A, B)

Duty (both heaters) 678,178,530 Btu/hr

Design pressure, tube 1650 psig

Design temperature, tube 525°F

Shell material SA516-70

Tube material SA688 TP 304

Tube sheet material SA350-LF2 w/304 SS overlay

Shell-side design pressure vacuum to 475 psig

Shell-side design temperature 525°F

Second-point heater (FW-E-2A, B)




Shell material SA516-70

Tube material SA688 TP304


Shell design pressure vacuum to 250 psig


Third-point heater (FW-E-3A, B)




Shell material SA-285-C








Fourth-point heater (FW-E-4A, B)




Shell material SA-285-C


Tube sheet material SA350-LF2 w/304 SS overlay (4A)SA266-CL2 w/304 SS overlay (4B)



Fifth-point heater (FW-E-5A, B)




Shell material ASTM-285C

Tube material SA688 TP 304

Tube sheet material SA105-N w/SS 304 overlay



Sixth-point heater (FW-E-6A, B)






Tube sheet material ASTM A515-70






Fifth-point external drain cooler (CN-DC-1A, 1B)






Tube sheet material ASTM A516-70



High-pressure heater drain pumps (SD-1A, B, C)

Capacity 3120 gpm


Design pressure (casing) 675 psi

Head 650 ft

Bowl material ASTM-A217-C5

Impeller ASTM A-217-C5

Low-pressure heater drain pumps (SD-P-2A, B)

Capacity 1380 gpm



Head 1150 ft

Casing material ASTM-A217-C5

Impeller material ASTM-A20-C5

Moisture separator-reheaters

Duty (total) 6.7 × 108 Btu/hr

Shell design pressure 265 psig


Tube-side design pressure 1125 psig

Tube-side design temperature 600°F

Tubes SA- 268 (TP439) Stainless Steel

Tube plates, tube support plates, shell, and water boxes

carbon steel




Tabl

e 10

.4-3

CR

ITE

RIA

FO

R A

UX

ILIA

RY

FE

ED

WA

TE

R S

YST

EM

DE

SIG

N-B

ASI

S C

ON

DIT

ION

S

Con

ditio

n or

Tra

nsie

ntC

lass

ific

atio

naC

rite

riaa

Add

ition

al D

esig

n C

rite

ria

Los

s of

mai

n fe

edw

ater

Con

ditio

nII

Peak

rea

ctor

coo

lant

sys

tem

pre

ssur

e no

t to

exc

eed

110%

of

desi

gn p

ress

ure.

No

cons

eque

ntia

l fue

l fai

lure

s.

Pres

suri

zer

does

not

bec

ome

wat

er s

olid

Stat

ion

blac

kout

Con

ditio

nII

Peak

rea

ctor

coo

lant

sys

tem

pre

ssur

e no

t to

exc

eed

110%

of

desi

gn p

ress

ure.

No

cons

eque

ntia

l fue

l fai

lure

s.

Pres

suri

zer

does

not

bec

ome

wat

er s

olid

Stea

mlin

e ru

ptur

eC

ondi

tion

IVR

egul

ator

y G

uide

1.18

3 do

se li

mits

. C

onta

inm

ent d

esig

n pr

essu

re n

ot

exce

eded

.

Feed

line

rupt

ure

Con

ditio

nIV

10C

FR10

0 do

se li

mits

. Con

tain

men

t de

sign

pre

ssur

e no

t exc

eede

d.C

ore

does

not

unc

over

Los

s of

all

ac p

ower

N/A

(b)

Sam

e as

bla

ckou

t ass

umin

g tu

rbin

e dr

iven

pum

p

Los

s of

coo

lant

Con

ditio

nII

I10

CFR

100

dose

lim

its. 1

0C

FR50

pea

k cl

ad te

mpe

ratu

re li

mits

.

Con

ditio

nIV

10C

FR50

.67

dose

lim

its. 1

0C

FR50

pe

ak c

lad

tem

pera

ture

lim

its.

Coo

ldow

nN

/A10

0°F/

hr54

7° to

350

°F

a.A

NS

IN

18.2

(th

is in

form

atio

n pr

ovid

ed f

or th

ose

tran

sien

ts p

erfo

rmed

in th

e F

SAR

).

b.A

ltho

ugh

this

tran

sien

t est

ablis

hes

the

basi

s fo

r au

xilia

ry f

eedw

ater

pum

p po

wer

ed b

y a

dive

rse

pow

er s

ourc

e, th

is is

not

eva

luat

ed r

elat

ive

to ty

pica

l cr

iter

ia s

ince

mul

tipl

e fa

ilur

e m

ust b

e as

sum

ed to

pos

tula

te th

is tr

ansi

ent.


Tabl

e 10

.4-4

SUM

MA

RY

OF

ASS

UM

PTIO

NS

USE

D I

N A

UX

ILIA

RY

FE

ED

WA

TE

R S

YST

EM

DE

SIG

N V

ER

IFIC

AT

ION

AN

AL

YSE

S

Tra

nsie

ntL

oss

of F

eedw

ater

(W

ith a

nd

With

out O

ffsi

te P

ower

)C

oold

own

Mai

n Fe

edlin

e B

reak

Mai

n St

eam

Lin

e B

reak

(C

onta

inm

ent)

Max

. rea

ctor

pow

er10

2% o

f ra

ted

ther

mal

pow

er

(102

% o

f 28

93M

Wt)

2963

MW

t10

2% o

f E

SD r

atin

g (1

02%

of

2910

MW

t)0%

(of

rat

ed)

- w

orst

cas

e (%

of

2775

MW

t)

Tim

e de

lay

from

eve

nt

to r

eact

or tr

ip2

sec

(del

ay a

fter

trip

)2

sec

2se

c0

sec

AFW

S ac

tuat

ion

sign

al/ti

me

dela

y(L

ow-l

ow/s

team

gen

erat

or

leve

l) 1

min

NA

a(L

ow-l

ow s

team

ge

nera

tor

leve

l) 1

min

Feed

wat

er is

olat

ion

actu

atio

n si

gnal

: saf

ety

inje

ctio

n si

gnal

0se

c (n

o de

lay)

; flo

w to

ste

am g

ener

ator

: 17

sec

afte

r m

ain

stea

m li

ne b

reak

(w

hich

is ti

me

of f

eedw

ater

is

olat

ion)

Stea

m g

ener

ator

wat

er

leve

l at t

ime

of r

eact

or

trip

(Low

-low

ste

am g

ener

ator

le

vel)

0%

NR

spa

nN

A(L

ow-l

ow s

team

ge

nera

tor

leve

l) 0

% N

R

span

Sam

e as

initi

al le

vel b

efor

e ev

ent

Initi

al s

team

gen

erat

or

inve

ntor

y10

3,83

9lb

m/s

team

gen

erat

or10

4,50

0 lb

m/s

team

ge

nera

tor

at 5

25.2

°F

89,0

55lb

m/s

team

ge

nera

tor

(int

act)

94

,148

lbm

/ste

am

gene

rato

r (f

aulte

d)

151,

000

lbm

/ste

am g

ener

ator

Rat

e of

cha

nge

befo

re

and

afte

r ac

tuat

ion

See

Figu

res

15.2

-31

and

15.2

-32

NA

Tur

naro

und

grea

ter t

han

2000

sec

See

Tabl

e6.

2-15

Dec

ay h

eat

AN

S19

79 S

tand

ard

AN

S19

73 S

tand

ard

120%

of

AN

S19

73 S

tand

ard

a.N

ot a

ppli

cabl

e.


Aux

iliar

y fe

ed-w

ater

pu

mp

desi

gn p

ress

ure

1133

psia

1133

psia

1133

psia

1025

psig

c

Min

imum

num

ber

of

stea

m g

ener

ator

s th

at

mus

t rec

eive

aux

iliar

y fe

edw

ater

flo

w

2 of

3N

Aa

1 of

3N

A

Rea

ctor

coo

lant

pum

p st

atus

All

oper

atin

g (W

ith O

ffsi

te

Pow

er)

Tri

pped

at r

eact

or tr

ip

(With

out O

ffsi

te P

ower

)

Tri

pped

All

oper

atin

gT

ripp

ed

Max

imum

aux

iliar

y fe

edw

ater

tem

pera

ture

120°

F10

0°F

120°

F12

0°F

Ope

rato

r ac

tion

Non

eN

A30

min

30m

in

Mai

n fe

edw

ater

pur

ge

volu

me/

tem

pera

ture

336.

9ft

3 /440

°FN

A20

3.1

ft3 /4

40°F

218

ft3 /4

41°F

Nor

mal

blo

wdo

wn

Non

e as

sum

edN

one

assu

med

Non

e as

sum

edN

one

assu

med

Sens

ible

hea

tSe

e co

oldo

wn

(b)

See

cool

dow

nSe

e co

oldo

wn

a.N

ot a

ppli

cabl

e.b.

Sour

ces

of s

ensi

ble

heat

are

con

serv

ativ

ely

dete

rmin

ed f

or e

ach

tran

sien

t. Se

nsib

le h

eat s

ourc

es th

at a

re c

onsi

dere

d in

clud

e th

e fo

llow

ing:

pri

mar

y w

ater

sou

rces

, ini

tiall

y at

rat

ed p

ower

tem

pera

ture

and

inve

ntor

y (R

CS

flui

d an

d li

quid

and

vap

or p

ress

uriz

er f

luid

); p

rim

ary

met

al s

ourc

es, i

niti

ally

at

rate

d po

wer

tem

pera

ture

(re

acto

r co

olan

t pip

ing,

pum

ps a

nd r

eact

or v

esse

l, pr

essu

rize

r, st

eam

gen

erat

or tu

be m

etal

and

tube

shee

t, st

eam

gen

erat

or

met

al b

elow

tube

shee

t, an

d re

acto

r ve

ssel

inte

rnal

s); s

econ

dary

wat

er s

ourc

es, i

niti

ally

at r

ated

pow

er te

mpe

ratu

re a

nd in

vent

ory

(liq

uid

and

vapo

r st

eam

gen

erat

or fl

uid

and

mai

n fe

edw

ater

pur

ge fl

uid

betw

een

stea

m g

ener

ator

and

AFW

sys

tem

pip

ing)

; and

sec

onda

ry m

etal

sou

rces

, ini

tiall

y at

rate

d po

wer

tem

pera

ture

(al

l ste

am g

ener

ator

met

al a

bove

tube

shee

t, ex

clud

ing

tube

s).

c.T

he m

axim

um s

team

gen

erat

or p

ress

ure

is th

e in

itia

l ste

ady

stat

e pr

essu

re, s

ince

this

is a

coo

ldow

n tr

ansi

ent.

Tabl

e 10

.4-4

(co

ntin

ued)

SU

MM

AR

Y O

F A

SSU

MPT

ION

S U

SED

IN

AU

XIL

IAR

Y F

EE

DW

AT

ER

SY

STE

M D

ESI

GN

VE

RIF

ICA

TIO

N A

NA

LY

SES

Tra

nsie

ntL

oss

of F

eedw

ater

(W

ith a

nd

With

out O

ffsi

te P

ower

)C

oold

own

Mai

n Fe

edlin

e B

reak

Mai

n St

eam

Lin

e B

reak

(C

onta

inm

ent)


Tim

e at

sta

ndby

/tim

e to

coo

ldow

n to

re

sidu

al h

eat r

emov

al

2hr

/4hr

2hr

/4hr

NA

aN

A a

Aux

iliar

y fe

edw

ater

fl

ow r

ate

600

gpm

(w

ith p

ower

)60

0gp

m (

with

out p

ower

)V

aria

ble

300

gpm

- 1

min

aft

er

trip

900

gpm

to b

roke

n st

eam

gen

erat

or,

350

gpm

to e

ach

inta

ct s

team

ge

nera

tor

b

a.N

ot a

ppli

cabl

eb.

The

impa

ct f

or in

crea

sing

this

aux

iliar

y fe

edw

ater

flo

w r

ate

to 9

70gp

m w

as s

ubse

quen

tly

eval

uate

d. T

hat e

valu

atio

n co

nfir

med

that

wit

h th

is in

crea

se

in a

uxili

ary

feed

wat

er f

low

, the

res

ults

of

the

anal

ysis

for

mai

n st

eam

line

bre

ak in

con

tain

men

t wou

ld s

till b

e w

ithin

the

acce

ptan

ce c

rite

ria.

The

au

xilia

ry f

eedw

ater

flo

w r

ate

to th

e in

tact

ste

am g

ener

ator

s is

am

ong

the

less

sig

nifi

cant

sec

onda

ry p

aram

eter

s. E

xpec

ted

vari

atio

ns in

aux

ilia

ry

feed

wat

er f

low

to th

e in

tact

ste

am g

ener

ator

s do

not

inva

lida

te th

e re

sults

of

the

anal

ysis

, so

flow

is c

onse

rvat

ivel

y m

odel

ed a

s a

cons

tant

flo

w r

ate.

Tabl

e 10

.4-4

(co

ntin

ued)

SU

MM

AR

Y O

F A

SSU

MPT

ION

S U

SED

IN

AU

XIL

IAR

Y F

EE

DW

AT

ER

SY

STE

M D

ESI

GN

VE

RIF

ICA

TIO

N A

NA

LY

SES

Tra

nsie

ntL

oss

of F

eedw

ater

(W

ith a

nd

With

out O

ffsi

te P

ower

)C

oold

own

Mai

n Fe

edlin

e B

reak

Mai

n St

eam

Lin

e B

reak

(C

onta

inm

ent)


Table 10.4-5FAILURE ANALYSIS OF AUXILIARY FEEDWATER COMPONENTS


Auxiliary feedwater pumps

All of the auxiliary feedwater pumps can be started manually as well as automatically. They are used to supply the steam generators with feedwater in the event of a loss of outside electric power to the plant and are essential for safe plant cooldown. All are designed as Seismic Class I. All three of the auxiliary pumps are started automatically when certain requirements are met (e.g., loss of station power, or steam generator low-low level indicators).

Motor-driven pump Fails to start No manual action is required. Turbine-driven pump is automatically started as shown above.

Turbine-driven pump

Fails to start Under this situation, no pump manual action is required. Motor-driven pumps are automatically started as shown above.

Turbine-driven pump

Fails during operation

No manual action is required. If this pump fails, it will not influence the operation of the two motor-driven pumps.

Piping All piping in this system complies with the seismic classification system of ANSI B31.7.

Break between the 110,000-gallon emergency condensate storage tank and steam generator feed pumps

There are three independent lines from the tank to the auxiliary pumps. The two motor-driven pumps are fed by 6-inch headers, while the turbine-driven pump is supplied by an 8-inch line. This water supply is backed up by a 6-inch line to the plant fire main. (Water can also be obtained from the plant service water system as well as the 300,000-gallon condensate storage tank.)

Break between the auxiliary feed pumps and steam generator

The three steam generators are independently supplied by a separate auxiliary feedwater pump. The turbine-driven pump supplies one steam generator through a 4-inch line while the remaining steam generators are each supplied by one of the motor-driven pumps through the 6-inch headers. The 4-inch header and the two 6-inch headers are isolated by valves to ensure independent flow paths. This system ensures flow to one steam generator for any combination of a high-energy pipe break and a single active failure (see Chapter 15 for additional information).


Valves There are various valves that will isolate the respective feedlines and the corrective action taken is the same for many of them (i.e., if the 6-inch line breaks, the line will be closed off at the storage tank). The major valves are discussed below.

Pressure-control valves in the two 6-inch headers from the auxiliary feedwater pumps

Fail Closed The two pressure-control valves in the two 6-inch headers and an orifice in the 4-inch line from the turbine-driven pump control backpressure to prevent pump runout due to a downstream pipe break. If any of the pressure-control valves fail closed, the pump can be shut down without affecting flow to the remaining steam generator.

Fail Open If any one of the pressure control valves fails open, the corresponding motor driven auxiliary feedwater pump will deliver a maximum flow of 845 gpm to its steam generator. This flow rate is below the 900 gpm which was assumed in the safety analysis. Therefore, the flow rate satisfies the requirements of the safety analysis, The pump can be shut down without affecting flow to the remaining steam generators.

Air-operated and motor-operated hand control valves for steam generator lines

Fail One steam generator supply has an air-operated hand-control valve and two steam generator supplies have motor-operated valves. The motor-operated valves are set in the open position. Any active failure of hand- control valves can only affect the flow to the respective steam generator. The flow of feedwater to the remaining two steam generators is unaffected. It should also be noted that the entire steam generator auxiliary feedwater system is provided with a tornado- and missile-protected enclosure.

Table 10.4-5 (continued) FAILURE ANALYSIS OF AUXILIARY FEEDWATER COMPONENTS



Table 10.4-6DESIGN DATA FOR MAJOR COMPONENTS OF THE

BEARING COOLING WATER SYSTEM

Bearing cooling water pumps (1BCP-1A and B)

Capacity 12,500 gpm

Head 185 ft

Operating temperature 33°F to 94°F



Casing material ASTM A48 C1. 30

Impeller ASTM B143 C1.1A

Bearing cooling water system cooling tower (1 & 2-BC-CT-1)

Flow per tower 12,500 gpm

Flow per cell 6250 gpm

Design inlet water temperature 115°F

Design outlet water temperature 92°F

Design ambient dry bulb 95°F

Design ambient wet bulb 78°F

Structural members Fiber Reinforced Plastic (FRP)

Fill and drift eliminator Polypropylene/PVC

Outer wall sheathing 16 oz/ft2 FRP

Cooling tower makeup pumps (BC-P-3A & B)

Capacity 850 gpm



Head 150 ft

Casing material B-62-4A (bronze)

Impeller B-62-4A (bronze)

Mechanical chiller condenser pumps (2-BC-P-5A & B)

Capacity 1500 gpm

Design temperature 32-95°F


Head 180 ft

Casing material (cast iron) A-48CL30B

Impeller material (bronze) CDAC83500


Figu

re10

.4-1

C

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Figure 10.4-2 TURBINE BUILDING FLOODING

AFTER CIRCULATING WATER EXPANSION JOINT RUPTURE a

a. Figure presented is based on the failure of a condenser outlet expansion joint. An inlet expansion joint failure would result in a change in the order of the filling of the tube cleaning equipment pit and miscellaneous equipment pits.


Figu

re 1

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Figu

re 1

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re 1

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re 1

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Figu

re 1

0.4-

4 FE

ED

WA

TE

R S

YST

EM

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

rum

, dia

m q

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dunt

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, sem

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i bib

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m li

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, ut e

lem

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m

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o m

agna

at a

ugue

. Aliq

uam

sap

ien

mas

sa, f

auci

bus

ac, e

lem

entu

m n

on, l

aore

et n

ec, f

elis

. Ves

tibul

um a

ccum

san

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m. I

n ul

lam

corp

er, d

ui s

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s eu

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od, a

nte

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i dap

ibus

ligu

la, i

d rh

oncu

s ip

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mi a

t tel

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Cla

ss a

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t ta

citi

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litor

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nt p

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onub

ia n

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. Qui

sque

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Etia

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. Int

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a an

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arc

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n m

i. V

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us n

on o

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itae

urna

al

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t ulla

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rper

. Cla

ss a

pten

t tac

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squ

ad li

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uent

per

con

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nos

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per

ince

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enae

os. I

n fr

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lla

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a ve

l odi

o. In

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e pl

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st. E

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raes

ent n

on li

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.


Figu

re 1

0.4-

5 C

HE

MIC

AL

FE

ED

SY

STE

M

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

rum

, dia

m q

uis

tinci

dunt

ele

men

tum

, sem

orc

i bib

endu

m li

bero

, ut e

lem

entu

m

just

o m

agna

at a

ugue

. Aliq

uam

sap

ien

mas

sa, f

auci

bus

ac, e

lem

entu

m n

on, l

aore

et n

ec, f

elis

. Ves

tibul

um a

ccum

san

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ttis

ipsu

m. I

n ul

lam

corp

er, d

ui s

ed c

ursu

s eu

ism

od, a

nte

wis

i dap

ibus

ligu

la, i

d rh

oncu

s ip

sum

mi a

t tel

lus.

Cla

ss a

pten

t ta

citi

soci

osqu

ad

litor

a to

rque

nt p

er c

onub

ia n

ostr

a, p

er in

cept

os h

ymen

aeos

. Qui

sque

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ncus

wis

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e do

lor.

Etia

m

elei

fend

. Int

eger

impe

rdie

t veh

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a an

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ed in

arc

u et

odi

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cum

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port

a. A

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n m

i. V

ivam

us n

on o

rci v

itae

urna

al

ique

t ulla

mco

rper

. Cla

ss a

pten

t tac

iti s

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squ

ad li

tora

torq

uent

per

con

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nos

tra,

per

ince

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enae

os. I

n fr

ingi

lla

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hac

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e pl

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st. E

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u. P

raes

ent n

on li

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.


Figu

re 1

0.4-

6 A

UX

ILIA

RY

FE

ED

WA

TE

R S

YST

EM

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

rum

, dia

m q

uis

tinci

dunt

ele

men

tum

, sem

orc

i bib

endu

m li

bero

, ut e

lem

entu

m

just

o m

agna

at a

ugue

. Aliq

uam

sap

ien

mas

sa, f

auci

bus

ac, e

lem

entu

m n

on, l

aore

et n

ec, f

elis

. Ves

tibul

um a

ccum

san

sagi

ttis

ipsu

m. I

n ul

lam

corp

er, d

ui s

ed c

ursu

s eu

ism

od, a

nte

wis

i dap

ibus

ligu

la, i

d rh

oncu

s ip

sum

mi a

t tel

lus.

Cla

ss a

pten

t ta

citi

soci

osqu

ad

litor

a to

rque

nt p

er c

onub

ia n

ostr

a, p

er in

cept

os h

ymen

aeos

. Qui

sque

rho

ncus

wis

i vita

e do

lor.

Etia

m

elei

fend

. Int

eger

impe

rdie

t veh

icul

a an

te. S

ed in

arc

u et

odi

o ac

cum

san

port

a. A

enea

n m

i. V

ivam

us n

on o

rci v

itae

urna

al

ique

t ulla

mco

rper

. Cla

ss a

pten

t tac

iti s

ocio

squ

ad li

tora

torq

uent

per

con

ubia

nos

tra,

per

ince

ptos

hym

enae

os. I

n fr

ingi

lla

ligul

a ve

l odi

o. In

hac

hab

itass

e pl

atea

dic

tum

st. E

tiam

tem

pus

lacu

s ac

arc

u. P

raes

ent n

on li

bero

.


Figu

re 1

0.4-

7 L

UB

RIC

AT

ING

OIL

SY

STE

M

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

rum

, dia

m q

uis

tinci

dunt

ele

men

tum

, sem

orc

i bib

endu

m li

bero

, ut e

lem

entu

m

just

o m

agna

at a

ugue

. Aliq

uam

sap

ien

mas

sa, f

auci

bus

ac, e

lem

entu

m n

on, l

aore

et n

ec, f

elis

. Ves

tibul

um a

ccum

san

sagi

ttis

ipsu

m. I

n ul

lam

corp

er, d

ui s

ed c

ursu

s eu

ism

od, a

nte

wis

i dap

ibus

ligu

la, i

d rh

oncu

s ip

sum

mi a

t tel

lus.

Cla

ss a

pten

t ta

citi

soci

osqu

ad

litor

a to

rque

nt p

er c

onub

ia n

ostr

a, p

er in

cept

os h

ymen

aeos

. Qui

sque

rho

ncus

wis

i vita

e do

lor.

Etia

m

elei

fend

. Int

eger

impe

rdie

t veh

icul

a an

te. S

ed in

arc

u et

odi

o ac

cum

san

port

a. A

enea

n m

i. V

ivam

us n

on o

rci v

itae

urna

al

ique

t ulla

mco

rper

. Cla

ss a

pten

t tac

iti s

ocio

squ

ad li

tora

torq

uent

per

con

ubia

nos

tra,

per

ince

ptos

hym

enae

os. I

n fr

ingi

lla

ligul

a ve

l odi

o. In

hac

hab

itass

e pl

atea

dic

tum

st. E

tiam

tem

pus

lacu

s ac

arc

u. P

raes

ent n

on li

bero

.


Figu

re 1

0.4-

8 ST

EA

M G

EN

ER

AT

OR

BL

OW

DO

WN

SY

STE

M

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

rum

, dia

m q

uis

tinci

dunt

ele

men

tum

, sem

orc

i bib

endu

m li

bero

, ut e

lem

entu

m

just

o m

agna

at a

ugue

. Aliq

uam

sap

ien

mas

sa, f

auci

bus

ac, e

lem

entu

m n

on, l

aore

et n

ec, f

elis

. Ves

tibul

um a

ccum

san

sagi

ttis

ipsu

m. I

n ul

lam

corp

er, d

ui s

ed c

ursu

s eu

ism

od, a

nte

wis

i dap

ibus

ligu

la, i

d rh

oncu

s ip

sum

mi a

t tel

lus.

Cla

ss a

pten

t ta

citi

soci

osqu

ad

litor

a to

rque

nt p

er c

onub

ia n

ostr

a, p

er in

cept

os h

ymen

aeos

. Qui

sque

rho

ncus

wis

i vita

e do

lor.

Etia

m

elei

fend

. Int

eger

impe

rdie

t veh

icul

a an

te. S

ed in

arc

u et

odi

o ac

cum

san

port

a. A

enea

n m

i. V

ivam

us n

on o

rci v

itae

urna

al

ique

t ulla

mco

rper

. Cla

ss a

pten

t tac

iti s

ocio

squ

ad li

tora

torq

uent

per

con

ubia

nos

tra,

per

ince

ptos

hym

enae

os. I

n fr

ingi

lla

ligul

a ve

l odi

o. In

hac

hab

itass

e pl

atea

dic

tum

st. E

tiam

tem

pus

lacu

s ac

arc

u. P

raes

ent n

on li

bero

.


Figu

re 1

0.4-

9 (

SHE

ET

1 O

F 4)

BE

AR

ING

CO

OL

ING

SY

STE

M

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

rum

, dia

m q

uis

tinci

dunt

ele

men

tum

, sem

orc

i bib

endu

m li

bero

, ut e

lem

entu

m

just

o m

agna

at a

ugue

. Aliq

uam

sap

ien

mas

sa, f

auci

bus

ac, e

lem

entu

m n

on, l

aore

et n

ec, f

elis

. Ves

tibul

um a

ccum

san

sagi

ttis

ipsu

m. I

n ul

lam

corp

er, d

ui s

ed c

ursu

s eu

ism

od, a

nte

wis

i dap

ibus

ligu

la, i

d rh

oncu

s ip

sum

mi a

t tel

lus.

Cla

ss a

pten

t ta

citi

soci

osqu

ad

litor

a to

rque

nt p

er c

onub

ia n

ostr

a, p

er in

cept

os h

ymen

aeos

. Qui

sque

rho

ncus

wis

i vita

e do

lor.

Etia

m

elei

fend

. Int

eger

impe

rdie

t veh

icul

a an

te. S

ed in

arc

u et

odi

o ac

cum

san

port

a. A

enea

n m

i. V

ivam

us n

on o

rci v

itae

urna

al

ique

t ulla

mco

rper

. Cla

ss a

pten

t tac

iti s

ocio

squ

ad li

tora

torq

uent

per

con

ubia

nos

tra,

per

ince

ptos

hym

enae

os. I

n fr

ingi

lla

ligul

a ve

l odi

o. In

hac

hab

itass

e pl

atea

dic

tum

st. E

tiam

tem

pus

lacu

s ac

arc

u. P

raes

ent n

on li

bero

.


Figu

re 1

0.4-

9 (

SHE

ET

2 O

F 4)

BE

AR

ING

CO

OL

ING

SY

STE

M

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

rum

, dia

m q

uis

tinci

dunt

ele

men

tum

, sem

orc

i bib

endu

m li

bero

, ut e

lem

entu

m

just

o m

agna

at a

ugue

. Aliq

uam

sap

ien

mas

sa, f

auci

bus

ac, e

lem

entu

m n

on, l

aore

et n

ec, f

elis

. Ves

tibul

um a

ccum

san

sagi

ttis

ipsu

m. I

n ul

lam

corp

er, d

ui s

ed c

ursu

s eu

ism

od, a

nte

wis

i dap

ibus

ligu

la, i

d rh

oncu

s ip

sum

mi a

t tel

lus.

Cla

ss a

pten

t ta

citi

soci

osqu

ad

litor

a to

rque

nt p

er c

onub

ia n

ostr

a, p

er in

cept

os h

ymen

aeos

. Qui

sque

rho

ncus

wis

i vita

e do

lor.

Etia

m

elei

fend

. Int

eger

impe

rdie

t veh

icul

a an

te. S

ed in

arc

u et

odi

o ac

cum

san

port

a. A

enea

n m

i. V

ivam

us n

on o

rci v

itae

urna

al

ique

t ulla

mco

rper

. Cla

ss a

pten

t tac

iti s

ocio

squ

ad li

tora

torq

uent

per

con

ubia

nos

tra,

per

ince

ptos

hym

enae

os. I

n fr

ingi

lla

ligul

a ve

l odi

o. In

hac

hab

itass

e pl

atea

dic

tum

st. E

tiam

tem

pus

lacu

s ac

arc

u. P

raes

ent n

on li

bero

.


Figu

re 1

0.4-

9 (

SHE

ET

3 O

F 4)

BE

AR

ING

CO

OL

ING

SY

STE

M

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

rum

, dia

m q

uis

tinci

dunt

ele

men

tum

, sem

orc

i bib

endu

m li

bero

, ut e

lem

entu

m

just

o m

agna

at a

ugue

. Aliq

uam

sap

ien

mas

sa, f

auci

bus

ac, e

lem

entu

m n

on, l

aore

et n

ec, f

elis

. Ves

tibul

um a

ccum

san

sagi

ttis

ipsu

m. I

n ul

lam

corp

er, d

ui s

ed c

ursu

s eu

ism

od, a

nte

wis

i dap

ibus

ligu

la, i

d rh

oncu

s ip

sum

mi a

t tel

lus.

Cla

ss a

pten

t ta

citi

soci

osqu

ad

litor

a to

rque

nt p

er c

onub

ia n

ostr

a, p

er in

cept

os h

ymen

aeos

. Qui

sque

rho

ncus

wis

i vita

e do

lor.

Etia

m

elei

fend

. Int

eger

impe

rdie

t veh

icul

a an

te. S

ed in

arc

u et

odi

o ac

cum

san

port

a. A

enea

n m

i. V

ivam

us n

on o

rci v

itae

urna

al

ique

t ulla

mco

rper

. Cla

ss a

pten

t tac

iti s

ocio

squ

ad li

tora

torq

uent

per

con

ubia

nos

tra,

per

ince

ptos

hym

enae

os. I

n fr

ingi

lla

ligul

a ve

l odi

o. In

hac

hab

itass

e pl

atea

dic

tum

st. E

tiam

tem

pus

lacu

s ac

arc

u. P

raes

ent n

on li

bero

.


Figu

re 1

0.4-

9 (

SHE

ET

4 O

F 4)

BE

AR

ING

CO

OL

ING

SY

STE

M

Etia

m v

enen

atis

acc

umsa

n en

im. M

auris

rut

rum

, dia

m q

uis

tinci

dunt

ele

men

tum

, sem

orc

i bib

endu

m li

bero

, ut e

lem

entu

m

just

o m

agna

at a

ugue

. Aliq

uam

sap

ien

mas

sa, f

auci

bus

ac, e

lem

entu

m n

on, l

aore

et n

ec, f

elis

. Ves

tibul

um a

ccum

san

sagi

ttis

ipsu

m. I

n ul

lam

corp

er, d

ui s

ed c

ursu

s eu

ism

od, a

nte

wis

i dap

ibus

ligu

la, i

d rh

oncu

s ip

sum

mi a

t tel

lus.

Cla

ss a

pten

t ta

citi

soci

osqu

ad

litor

a to

rque

nt p

er c

onub

ia n

ostr

a, p

er in

cept

os h

ymen

aeos

. Qui

sque

rho

ncus

wis

i vita

e do

lor.

Etia

m

elei

fend

. Int

eger

impe

rdie

t veh

icul

a an

te. S

ed in

arc

u et

odi

o ac

cum

san

port

a. A

enea

n m

i. V

ivam

us n

on o

rci v

itae

urna

al

ique

t ulla

mco

rper

. Cla

ss a

pten

t tac

iti s

ocio

squ

ad li

tora

torq

uent

per

con

ubia

nos

tra,

per

ince

ptos

hym

enae

os. I

n fr

ingi

lla

ligul

a ve

l odi

o. In

hac

hab

itass

e pl

atea

dic

tum

st. E

tiam

tem

pus

lacu

s ac

arc

u. P

raes

ent n

on li

bero

.

Chapter 10: Steam and Power Conversion System Table of

Documents

Transcript of Chapter 10: Steam and Power Conversion System Table of